Zero droop voltage control for smart inverters

ABSTRACT

Systems and methods for controlling grid voltage include a distribution power network and one or more smart inverters at or near the edge of the distribution power network, each smart inverter configured to absorb or insert VARs to control the voltage based on a reference Q value, wherein the reference Q value is calculated by a reference Q calculator. A reference Q calculator includes a processor and a non-transitory computer readable memory with software embedded thereon, the software configured to cause the processor to receive a voltage measurement taken at or near the edge of a power distribution grid, a voltage band value, and a voltage set point value, determine a difference, e v , between the voltage measurement and the voltage set point, generate a new reference Q value if an absolute value of e v  is greater than the voltage band value, and cause the smart inverter to either absorb or insert VARs depending on the sign of e v .

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of and claims thebenefit of U.S. patent application Ser. No. 14/659,418, filed Mar. 16,2015, entitled Systems and Methods for Edge of Network Voltage Controlof a Power Grid,” which claims the benefit of U.S. patent applicationSer. No. 13/488,330, filed Jun. 4, 2012, entitled “Systems and Methodsfor Edge of Network Voltage Control of a Power Grid,” which claims thebenefit of U.S. Provisional Patent Application No. 61/535,892, filedSep. 16, 2011, entitled “Systems and Methods of a Distributed DynamicVAR (D-DVAR) Compensator,” U.S. Provisional Patent Application No.61/567,580, filed Dec. 6, 2011, entitled “Systems and Methods forDynamic VAR Optimization,” U.S. Provisional Patent Application No.61/579,610, filed Dec. 22, 2011, entitled “Systems and Methods forManaging Power,” U.S. Provisional Patent Application No. 61/635,799,filed Apr. 19, 2012, entitled “Systems and Methods for Dynamic AC LineVoltage Regulation with Energy Saving Tracking,” and U.S. ProvisionalPatent Application No. 61/635,797, filed Apr. 19, 2012, entitled“Systems and Methods for Fast VAR Source with Anti-Resonance Function,”each of which is incorporated herein by reference in its entirety.

FIELD

The present disclosure generally relates to power distribution gridnetwork optimization strategies. More particularly, various embodimentsof the disclosure relate to controlling voltage at or near the edge ofthe power grid through the use of photovoltaic inverters that deliver orabsorb VARs.

BACKGROUND

The conventional approach to power distribution grid voltage control isbased on techniques developed about 70 years ago, one goal of which isto control demand (either raising or lowering demand). In recent years,highly complex and expensive systems have been required to implementimproved effective voltage control and conservation voltage reduction(CVR) based demand reduction, one example of which is power distributiongrid voltage control. Typically, utilities operate in a narrow band of116-124 volts, even though level ‘A’ service allows for a range of114-126 volts. The difficulty in adhering to a tight regulation bandarises from normal fluctuations in incoming line voltage at thesubstation, as well as load changes along the feeder. These changescause the line voltage to vary, with utilities required to maintainvoltage for consumers within specified bounds.

A primary purpose of voltage control is maintaining acceptable voltagelevels, e.g., per the American National Standards Institute (ANSI)standards or similar standard setting organizations, at the serviceentrance of customers served by a feeder under all possible operatingconditions. Electric utilities traditionally maintain distributionsystem voltage within the acceptable range using transformers withmoveable taps that permit voltage adjustments under load. Other methodsinclude de-energized tap changers (DETC) where the transformers arede-energized for changing the tap setting and then re-energized once thetap is changed. When utilizing the DETC method, the tap remains fixedonce changed and the voltage is not actively regulated. Voltageregulators located in substations and on the lines, as well assubstation transformers are commonly used for voltage control purposes.These transformers, sometimes referred to as Load Tap Changers (LTCs),and are equipped with a voltage-regulating controller that determineswhether to raise or lower the transformer tap settings or leave the tapsetting unchanged based on “local” voltage and load measurements.

With electric grid modernization strategies gaining importance andmomentum as utilities push ahead to upgrade their aging infrastructure,Volt Var Control (VVC) has become an important tool to regulate voltage.However, current VVC tools can't deliver the needed performance benefitsdue to extreme voltage volatility at the edge of the grid, the inabilityof existing tools to see these conditions and characterize these voltageconditions accurately across the feeder. In the recent times, the costof PV installation has dramatically reduced, which has consequently ledto an increase in distributed photovoltaic voltage (PV) on electricdistribution network. The increase in introduction of solar power can beattributed to an increase in the number of solar power utilities beingformed to facilitate broad deployment of distributed energy technologiessuch as rooftop solar PV systems. For example, policies in somecountries provide subsidies and incentivize the installation ofresidential and commercial solar PV systems through two mechanismsnamely, feed-in tariffs (FIT) and net energy metering (NEM). Theincreased penetration of distributed PV systems may exacerbate theseissues because the voltage fluctuations introduced by PV may consume theANSI band and leave little room for VVC. FIG. 16 depicts an example ofvoltage volatility measured at a distribution grid edge over a number ofdays. Specifically, in the example in FIG. 16, volatility as high as 17%was measured.

VVC has been achieved using centralized optimization engines thatcontrol volts and VARs on the power grid using primary side assets. Thisis realized by changing the tap settings of LTCs and LVRs to achievevoltage control or by switching ON/OFF capacitor banks to achieve VARcontrol. The aim of these optimization engines is to ensure thatvoltages at the customer meters are maintained within a specified bande.g. ANSI C84.1 specifies 114V to 126V as the ANSI-A band.

Many of these existing primary assets are designed to handle gridvoltage fluctuations at a rather slow rate (e.g., 30 sec to 15 minutes).Further, they are designed to switch or operate no more than a few times(e.g., 5-10 times a day) to ensure a long life. However, with moredistributed PV on the electric grid causing high levels of variability,these primary assets may need to operate much more than designed. Thisoveruse may effectively reduce the life expectancy of the primaryassets.

One example solution used to manage some of this voltage volatilityemploys PV inverters that have the capability of regulating reactivepower (leading and lagging) in addition to supplying real powergenerated from PV panels. A volt-VAR droop curve, similar to the curveillustrated in FIG. 17, may be used by control logic to control thereactive power output from the smart inverters to maintain voltageswithin the specified limits. Theoretically this curve ensures that theright control actions are taken to maintain local voltage within thespecified limits. However, as illustrated in FIG. 17, the curve spans awide range around the normal voltage (e.g., +/−3% to 5% in many cases).Thus, most of the specified band is consumed for achieving the volt-VARcontrol objective. Also, introducing large numbers of inverters on thegrid may increase instability and operational problems related tounexpected interaction between inverters (e.g., infighting).

SUMMARY

Embodiments of the present disclosure are directed towards systems andmethods for controlling grid voltage with a smart inverter. In someembodiments, the system includes a distribution power network and asmart inverter coupled thereto (e.g., at or near the edge of the powerdistribution network). In several embodiments, multiple smart invertersmay be coupled at multiple respective locations on the powerdistribution network, wherein each smart inverter may be configured toabsorb or insert VARs to control the voltage at the edge of the grid. Toprevent infighting, one or more of the smart inverters may be configuredto insert or absorb VARs based on a reference Q value. One or more ofthe smart inverters may include a controller communicatively coupled toa reference Q calculator. In some examples, the reference Q calculatormay be embedded on the controller, external to the controller butdisposed within the smart inverter, or external to the smart inverter.In some examples, multiple smart inverters may share the same referenceQ calculator.

In some embodiments, the reference Q calculator may include a processorand a non-transitory computer readable memory with software embeddedthereon. The software may be configured to cause the processor toreceive a voltage measurement from an edge of a power distribution grid,a voltage band value, and a voltage set point value. For example, thevoltage measurement may be made using a voltage sensor (e.g., avoltmeter) connected at or near the edge of the power distributionnetwork, or disposed within the smart inverter itself. The voltage bandvalue and voltage set point may each be set by a user, calculated,centrally controlled, predetermined within the smart inverter (e.g.,during manufacturing thereof, or set during calibration procedures. Thesoftware may be further configured to determine a difference, e_(v),between the voltage measurement and the voltage set point and generate anew reference Q value if an absolute value of e_(v) is greater than thevoltage band value.

In some examples of the disclosure, the new reference Q value is set totrigger the smart inverter to absorb VARs if e_(v) is negative in valueand to cause the smart inverter to inject VARs if e_(v) is positive invalue. The new reference Q value may be set as a function of e_(v) ². Insome examples, the software is also configured to cause the processor togenerate the new reference Q value as a function of a gain value, K_(q).K_(q) may be set by a user, centrally controlled, pre-determined, orcalculated, for example, as a randomized value. The software may furtherbe configured to cause the processor to receive a maximum Q referencevalue and to limit the new reference Q value to the maximum Q referencevalue. The maximum Q reference value may be set as a function of arating S. For example, S may be pre-determined (e.g., set by themanufacture or during a calibration procedure), set by a user, orcentrally controlled.

In some embodiments, the software may be configured to monitor thevoltage measurement for oscillation, cause the processor to set a delaytimer if the voltage measurement is oscillating, and maintain thecurrent reference Q value until the delay timer expires.

Some embodiments of the disclosure provide a method of controllingvoltage by inserting or absorbing VARs at the edge of a powerdistribution grid implemented by a smart inverter. The method mayinclude receiving a voltage measurement from an edge of a powerdistribution grid, a voltage band value, and a voltage set point valueand determining a difference, e_(v), between the voltage measurement andthe voltage set point. The method may also include generating a newreference Q value if an absolute value of e_(v) is greater than thevoltage band value. The method may also include causing the smartinverter to absorb VARs, based on the new reference Q value, if e_(v) isnegative in value and to inject VARs, based on the new reference Qvalue, if e_(v) is positive in value. In some examples, the newreference Q value is generated as a function of e_(v) ².

In some examples, the method may also include generating a gain value,K_(q), wherein the new reference Q value is generated as a function ofK_(q). K_(q) may be set by a user, centrally controlled, pre-determined,or calculated, for example, as a randomized value. The method may alsoinclude generating a maximum Q reference value and to limiting the newreference Q value to the maximum Q reference value. In some examples,the maximum Q reference value as a function of a rating value, S.

Some embodiments of the method include setting a delay if the voltagemeasurement is oscillating and maintaining the current reference Q valueuntil the delay expires. The method may further include generating arandomized value, K_(T), wherein the delay is set as a function of K_(T)and e_(v).

Other features and aspects of the disclosure will become apparent fromthe following detailed description, taken in conjunction with theaccompanying drawings, which illustrate, by way of example, the featuresin accordance with embodiments of the disclosure. The summary is notintended to limit the scope of the invention, which is defined solely bythe claims attached hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure, in accordance with one or more variousembodiments, is described in detail with reference to the followingfigures. The drawings are provided for purposes of illustration only andmerely depict typical or example embodiments of the disclosure. Thesedrawings are provided to facilitate the reader's understanding of thedisclosure and shall not be considered limiting of the breadth, scope,or applicability thereof.

FIG. 1a depicts a typical distribution feeder fed from a singlesubstation in some embodiments.

FIG. 1b depicts a distribution feeder fed from a single substation andincluding a plurality of edge of network voltage optimization (ENVO)devices in some embodiments.

FIG. 1c depicts another distribution feeder fed from a single substationand including the plurality of ENVO devices in some embodiments.

FIG. 2 is a diagram depicting voltage drop along feeders due to loadswithout the implementation of capacitor banks in the prior art.

FIG. 3a is a diagram depicting a power distribution grid withshunt-connected, switch-controlled VAR sources at or near each load insome embodiments.

FIG. 3b is another diagram depicting a power distribution grid withshunt-connected, switch-controlled VAR sources at or near each load insome embodiments.

FIG. 4a is a circuit diagram of an exemplary switch-controlled VARsource which may be connected in shunt in some embodiments.

FIG. 4b is a graph that depicts activating the semiconductor switchrelative to the relay to engage VAR compensation in some embodiments.

FIG. 4c is a graph that depicts deactivating the semiconductor switchrelative to the relay to disengage VAR compensation in some embodiments.

FIGS. 5a and 5b are graphs that depict a desired voltage range inrelation to set points in some embodiments.

FIG. 6 is a flow chart for voltage regulation by a switch-controlled VARsource in some embodiments.

FIG. 7 is a time sequence of events of network regulation with twoswitch-controlled VAR sources in some embodiments.

FIG. 8 is a graph that depicts a typical voltage profile at variousnodes in the prior art.

FIG. 9 is a graph that depicts relatively flat voltage profile atvarious nodes in some embodiments realized with 240 switch controlledVAR sources operating to regulate the voltage along the edge of thedistribution feeder.

FIG. 10 is a graph that depicts a dynamic response of the ENVO system toline voltage changes (which can be caused by solar PV plants), as wellas to step changes in line loading in some embodiments.

FIG. 11a is another circuit diagram of a plurality of switch-controlledVAR sources that may be within or next to a pole top transformer or anygrid asset in some embodiments.

FIG. 11b depicts a switch-controlled VAR source in some embodiments.

FIG. 11c depicts a plurality of switch-controlled VAR sources in someembodiments.

FIG. 11d depicts a controller in some embodiments.

FIG. 11d -1 is an exploded schematic view of the corresponding elementof FIG. 11 d.

FIG. 11d -2 is an exploded schematic view of the corresponding elementof FIG. 11 d.

FIG. 11d -3 is an exploded schematic view of the corresponding elementof FIG. 11 d.

FIG. 11d -4 is an exploded schematic view of the corresponding elementof FIG. 11 d.

FIG. 11e depicts power module comprising ADC circuitry and ZCD circuitrycoupled to the controller in some embodiments.

FIG. 12 illustrates an exemplary power system including a VAR cloud insome embodiments.

FIG. 13 is a block diagram of an exemplary distributed controllable VARsource (DCVS) in some embodiments.

FIG. 14a is a control diagram of an exemplary method of controlling aDCVS in some embodiments.

FIG. 14b depicts an example method of controlling a DCVS in a scenariowhere the DCVS is integrated into a customer-located asset, such as asmart meter.

FIG. 15 is a block diagram of an exemplary digital device.

FIG. 16 is a chart illustrating voltage volatility measured at the edgeof the power distribution grid.

FIG. 17 is a chart illustrating a Q-V droop curve used for controllingreactive power as a function of voltage.

FIG. 18A is a chart showing measured voltage volatility over multipledistribution transformers when now edge of network voltage control isused.

FIG. 18B is a chart showing measured voltage volatility over multipledistribution transformers when edge of network voltage control isapplied.

FIG. 19 depicts an example power system with PV inverters on adistribution feeder.

FIG. 20 is an example method of generating a Q_(ref) value for a smartinverter, consistent with embodiments disclosed herein.

FIG. 21A is a block diagram of a smart inverter incorporating a Q_(ref)calculator, consistent with embodiments disclosed herein.

FIG. 21B is a block diagram of a smart inverter in communication with anexternal Q_(ref) calculator, consistent with embodiments disclosedherein.

FIG. 22 depicts an example power distribution system with smartinverters.

FIG. 23 is a schematic representation of an example computing modulethat may be used to implement various features of embodiments describedin the present disclosure.

These figures are not intended to be exhaustive or to limit theinvention to the precise form disclosed. It should be understood thatthe embodiments of the disclosure can be practiced with modification andalteration, and that the invention be limited only by the claims and theequivalents thereof.

DETAILED DESCRIPTION

Grid edge voltage control has been demonstrated through the use ofdedicated shunt VAR solutions, such as the Edge of Network GridOptimization (ENGO) devices as disclosed herein. These devices activelyand dynamically inject the right amount of vars at the grid edge toregulate voltage within a very tight band. With multiple distributedENGO devices set to operate at the same set point, a highly volatilesystem (e.g., illustrated in the chart in FIG. 5A) can be tamed into atightly regulated deterministic system (e.g., as illustrated in thechart in FIG. 5B). As there are multiple devices in the system allregulating the voltage at the same set point, the problem of huntingneeds to be addressed. The problem of hunting or infighting is resolvedby using two fundamental principles: (1) The rate of VAR injection bythe individual devices is directly proportional to the deviation inobserved voltage and commanded set point voltage; and (2) the magnitudeof VAR injection is directly proportional to the deviation in observedvoltage and commanded set point voltage. Each time VAR may be injected,a randomization may be applied to the gain that controls the magnitudeof VARs injected. A similar strategy may be applied to PV smartinverters, as described in more detail below with respect to FIGS. 1-15.

New requirements for distributed dynamic voltage control are emerging,driven by distributed renewable energy penetration and the need toincrease grid capacity without building new lines or infrastructure.Applications such as Conservation Voltage Reduction (CVR) and Volt VAROptimization (VVO) promise 3-5% increase in system capacity, simply bylowering and flattening the voltage profile along a distribution grid.To achieve CVR and VVO in the prior art, improvements to the power gridare slow in operation, difficult to model due to increased complexity ofthe overall system, require considerable back end infrastructure (e.g.,modeling, and a centralized, computation and communication facility),are expensive to install in sufficient numbers to improve performance,and difficult to maintain. Further, conventional VVO schemes realizepoor voltage regulation due to few control elements and poor granularresponse. It should be noted that the term voltage and VAR controldevices, as utilized herein, can refer to devices that, in manipulating(sourcing) VARs, impacts both a local and system VAR flow, therebyimpacting local and system voltages.

In various embodiments discussed herein, line voltage may be regulatedat or near every customer point (i.e., at the load along a distributionpower grid). For example, a utility may install a shunt-connected,switch-controlled volt-ampere reactive (VAR) source at each customerlocation. Each shunt-connected, switch-controlled volt-ampere reactive(VAR) source may detect a voltage proximate to the device and make adetermination to enable a VAR compensation component (e.g., capacitor(s)and/or inductor(s)) to regulate voltage on the network. The plurality ofshunt-connected, switch-controlled volt-ampere reactive (VAR) sources,switching independently, may operate collectively to flatten the voltagecurve (e.g., voltage impact along a medium voltage distribution feederstarting from a substation) along a power network. The plurality of VARsources may be controlled to prevent fighting between sources, whileallowing connected points to reach a desired voltage set point with muchhigher granularity and accuracy.

If distributed VAR compensation is implemented, the utility may realizeseveral benefits. For example, a desired voltage profile may bemaintained optimally along the line even as system configurationchanges, system losses may decrease, and/or system stability andreliability may be improved. New cascading grid failure mechanisms, suchas Fault Induced Delayed Voltage Recovery (FIDVR) may also be avoidedthrough the availability of distributed dynamically controllable VARs.

In various embodiments, distributed fast voltage controllers and/orcompensators at or near a power network edge provides a solution that isable to act autonomously on local information with little to noinfighting. This approach may remove uncertainty about the voltagevariations at a range of nodes, flatten the voltage profile along theedge of the network, and allow a Load Tap Changer (LTC) to drop thevoltage to the lowest level possible.

FIG. 1a depicts a typical distribution feeder 106 fed from a singlesubstation 102 in some embodiments. Standard design practice involvesthe use of load tap changing (LTC) transformers 104 at substations 102,with fixed and switchable medium voltage capacitors on the feeder. FIG.1 depicts a series of houses (i.e., loads) 110, 112, 114, and 116 thatreceive power from various distribution feeders coupled to the primaryfeeder 106 (e.g., distribution feeders separated from the primary feederby transformers 108 a-d). In the prior art, as the distance from thesubstation 102 increases, utility voltage 118 along the primary feeder(e.g., medium voltage distribution feeder 106) decreases.

In the prior art, load tap changers, slow acting capacitor banks, andline voltage regulators may be sporadically placed along one or moreprimary feeders 106 to improve voltage range. Without ConservationVoltage Reduction or CVR, the first houses 110 have a required utilityvoltage of approximately 124.2 volts. Houses 112 have a significantlyreduced utility voltage of approximate 120-121 volts. Houses 114 furtherhave a required voltage between 115 and 116 while houses 116 have arequired voltage between 114 and 115.

FIG. 1b depicts a distribution feeder 106 fed from a single substation102 and including a plurality of edge of network voltage optimization(ENVO) devices 120 a-d in some embodiments. In various embodiments, VARcompensators (e.g., or any VAR source), including, for example, ENVOdevices 120 a-d, may be placed at or near any number of the loads (e.g.,houses 110, 112, 114, and 116). As a result, the overall voltage rangemay be flattened along the distance from the substation 102 therebysaving energy, increasing responsiveness, and improving overall controlalong longer distribution feeders. In order to avoid infighting betweenone or more VAR sources, the action of switching (e.g., the timing ofswitching or the point at which VAR compensation is engaged/disengaged)may be different between all or a portion of the VAR sources.

The VAR source may each act (e.g., activate or deactivate one or moreVAR components such as a capacitor and/or inductor) quickly andindependently, based at least on voltages proximate to the VAR sources,respectively, to improve voltage regulation and achieve Edge of NetworkVolt Optimization (ENVO) (see ENVO line 122). The ENVO line 122 depictsthat the voltage required for houses 110 is approximately 120 volts.Houses 112, 114, and 116, may require a reasonably flat voltage rangearound approximately 120 volts as well. Those skilled in the art willappreciate that the ENVO line 122 achieves a desired flattening of therequired voltage range while the line indicating utility voltage 118without VAR compensation drops precipitously.

FIG. 1c depicts another distribution feeder 106 fed from a singlesubstation 102 and including the plurality of ENVO devices 120 a-d insome embodiments. In various embodiments, the ENVO devices 120 a-d mayfurther apply Conservation Voltage Reduction (CVR) to further reducerequired voltage. Line 124 represents the voltage required for houses110, 112, 114, and 116 with ENVO devices 132 a-b applying CVR. Forexample, line 124 (like ENVO line 122) is relatively flat. Houses 110and 112 may require approximately 115.2 volts while houses 114 mayrequire approximately 115 volts. Further, houses 116 may require 115.4volts in this example. The need to improve system capacity utilizationis driving utilities to implement peak demand reduction and capacityexpansion using techniques such as Conservation Voltage Reduction (CVR)and Volt VAR Optimization (VVO) on non-ENVO devices. Utility companiescurrently apply CVR by receiving information from multiple points in thepower grid, modeling the performance, modeling proposed improvements,and potentially coordinating activities of capacitor banks along theprimary feeder on the medium voltage side of the transformers.

Poor controllability of preexisting voltage regulation devices presentssevere challenges to managing voltage variations for system planners andoperators. In particular, poor controllability limits the length of adistribution feeder that can be managed. Poor controllability alsolimits the load variability that can be handled, while keeping allvoltages at end-user locations within bounds.

Further, new trends are seeing an increased use of sectionalizers withbreaker/reclosers to isolate faulted segments and to restore power toother non-faulted line segments, resulting in a significant change inthe network, and voltage profiles. Increased use of networkreconfiguration also makes the task of placing capacitor banks and LTCsat fixed locations more problematic, as the placement has to meet theneeds of multiple configurations. Moreover, the increasing use ofdistributed generation resources, such as roof top photovoltaic (PV)arrays can result in a reversal of power flows locally, with higher linevoltages farther away from the substation, and a breakdown of anyvoltage regulation algorithm that was implemented.

Those skilled in the art will appreciate that VAR sources at or near theedge of the power grid may individually react and correct for higherline voltages that may be a result of PV arrays (e.g., green energyimprovement such as solar panels). These VAR sources may allow both thecustomer and the network to enjoy the benefits of green power withoutsignificantly redesigning or altering the grid to accommodate thechange. Since the edge of the network is quickly and independentlyreactive to events or changes along the power grid, a centralizedalgorithm, containing a complete state of the grid including allvariables that affect load and input, for slow voltage control andregulation may also become unnecessary.

FIG. 2 is a diagram depicting voltage drop along feeders due to loadswithout the implementation of capacitor banks in the prior art. Asdepicted in FIG. 2, the length of the feeder lines from the substationis limited by the voltage drop. In this example, there is a 10% variancein available voltage. In the prior art, the objective is to keep voltagewithin a broad band. As few control handles are available, only verycoarse control is possible. Ideally, the voltage should be closelyregulated to specifications all along the line, including in thepresence of dynamic fluctuations. With few sensors, few correctionpoints, slow communication, and a limited number of operations, priorart control is unable to meet the dynamic control requirements of thenew and future distribution power grid.

By utilizing sporadically placed capacitor banks, voltage regulation maybe implemented to flatten the available voltage range and reduce losses.The capacitor banks may operate based on temperature, for example, orbased on commands from a centralized control facility. When based ontemperature, for example, to avoid interactions and to maximize switchlife of the capacitor banks, switching to activate or deactivate one ormore capacitors is infrequent and slow. Capacitor banks that areoperated under the control a centralized facility may be individuallycommanded to avoid interactions.

In spite of the attempts of controlling voltage through CVR, drops alongthe length of the feeder are only marginally affected by the activationof the capacitor banks. In these examples, the capacitor bank may beswitched three-to-four times per day. The process maybe slow as well. Inone example, it may take up to fifteen minutes to: 1) detect conditions;2) provide the conditions to a centralized facility; 3) the centralizedfacility model conditions and make a determination to enable or disablea capacitor bank; 4) provide a command to one or more capacitor banks;and 5) receive the command and perform the switching. Even if one ormore of these disadvantages were overcome, there may still be infightingbetween multiple devices attempting to control voltage. For example,multiple thyristor switched capacitors may fight with each other as eachdevice attempts to compensate for a power state of the power network. Asthe thyristor switched capacitors work at cross purposes, they tend toovercompensate and undercompensate while constantly reacting to thecorrections of other thyristor switched capacitors on the power network.

FIG. 3a is a diagram depicting a power distribution grid withshunt-connected, switch-controlled VAR sources at or near each load insome embodiments. Loads are depicted as houses or residences. Inaddition to houses or residences, those skilled in the art willappreciate that the loads can be any loads including, but not limitedto, commercial or industrial establishments. A load is any component,circuit, device, piece of equipment or system on the power distributionnetwork which consumes, dissipates, radiates or otherwise utilizespower. A power distribution grid is an electrical grid, such as aninterconnected network, for delivering electricity from suppliers toconsumers.

In this example, voltage may be regulated at or near the edge of thenetwork thereby allowing edge of network volt optimization (ENVO). Anedge of the network is the portion of a power distribution network thatis proximate to the load that is to receive power. In one example, theload is a customer load. An edge of the network may be on thelow-voltage side of a transformer. For example, the edge of the networkmay comprise one or more feeder lines configured to provide power tomultiple customer loads (e.g., housing residences).

In FIG. 3, a substation provides power to residences (e.g., loads) overa series of regional distribution feeders. Each residence andshunt-connected, switch-controlled VAR source is coupled to the powerdistribution grid. In various embodiments, each shunt-connected,switch-controlled VAR source is configured to detect voltage and adjustnetwork volt-ampere reactive (VARs) based on the detected voltage. Inone example, the shunt-connected, switch-controlled VAR source enables acapacitor and/or an inductor to change (e.g., reduce or eliminate) thereactive power of the power distribution grid thereby regulating voltageof the network (i.e., network voltage). The change in reactive power mayreduce the voltage drop along the distribution feeder.

As discussed regarding FIG. 1, shunt-connected, switch-controlled VARsources may be placed at or near any number of the loads. As a result,the overall voltage range may be flattened along the distance from thesubstation thereby saving energy, increasing responsiveness, andimproving overall control along longer distribution feeders. The VARsource may each act (e.g., activate or deactivate one or more VARcomponents such as a capacitor and/or inductor) quickly andindependently, based at least on voltages proximate to the VAR sources,respectively, acting collectively to improve voltage regulation andachieve ENVO. FIG. 3 depicts that the voltage distribution drop isflatter, for example a +/−2% variance across the network depicted inFIG. 3 without the implementation of the capacitor banks.

FIG. 3b is another diagram depicting a power distribution grid withshunt-connected, switch-controlled VAR sources at or near each load insome embodiments. In FIG. 3b , a substation 302 with a load top changer(LTC) 304 feeds a distribution feeder 306 with line inductancethroughout the distribution feeder 306. Loads 312, 314, 316, and 318receive power from the distribution feeder 306 via transformers 310 a-drespectively. Further, each subfeeder between a transformer and theloads may include one or more ENVO devices 310 a-e that may beconfigured to act as one or more VAR compensators. In variousembodiments, multiple ENVO devices (e.g., ENVO VAR units) may bedeployed along the length of a typical distribution feeder to flattenthe required voltage and respond to network conditions.

In various embodiments, an optional central controller 320 maycommunicate with one or more of the ENVO devices 310 a-e to receivesensor information and/or behavior information regarding the actions ofone or more ENVO devices 310 a-e. In some embodiments, one or more ofthe ENVO devices 310 may include a communication interface configured tocommunicate with each other and/or the central controller 320. Thecentral controller 320 may, in some embodiments, provide one or more setpoints (discussed herein) that may assist in controlling when one ormore of the ENVO devices 310 become active (e.g., based on comparing oneor more set points to voltage of a portion of the power distributionnetwork. The central controller 320 is further discussed herein.

FIG. 4a is a circuit diagram of an exemplary switch-controlled VARsource 400 which may be connected in shunt in some embodiments. Theswitch-controlled VAR source 400 may be a part of a large number ofswitch-controlled VAR sources 400 at or near an edge of the powerdistribution grid (i.e., the power network).

At a high level, the switch-controlled VAR source 400 comprises acapacitor 412 (e.g., a VAR compensation component) that is controlledthrough a relay 414 in parallel with a semiconductor switch 416 (e.g.,triac 420—NTC 418 is optional). A processor, such as controller 426, maycontrol the relay 414 and semiconductor switch 416 based on voltage. Forexample, the controller 426 may detect voltage proximate to theswitch-controlled VAR source 400 (e.g., through line 402). Based on thedetected voltage, the controller 426 may enable or disable the capacitorby controlling the relay 414 and semiconductor switch 416. As discussedherein, the relay 414 and semiconductor switch 416 may work together toprotect and prolong the life of various components of theswitch-controlled VAR source 400 during switching operations.

The exemplary switch-controlled VAR source 400 comprises lines 402 and430, fuse 404, inductor 406, resistors 408, 410, 418, 422, and 424,capacitor 412, relay 414, a switch 416 comprising an optional NTC 418and triac 420, controller 426, and power supply unit (PSU) 428. Lines402 and 430 may be coupled to a feeder such as a feeder on the lowvoltage side of a transformer. In one example, lines 402 and 430 may becoupled to any line or feeder configured to provide power to one or moreloads (e.g., on or at the edge of a network). In some embodiments, theswitch-controlled VAR source 400 is proximate to a residential orcommercial load. For example, the switch-controlled VAR source 400 maybe within a smart meter, ordinary meter, or transformer within proximityto a load. Those skilled in the art will appreciate that theswitch-controlled VAR source 400 may be within any grid asset.

The fuse 404 is configured to protect the switch-controlled VAR source400 from voltage spikes, transients, excessive current, or the like. Thefuse 404 may be any fuse and may be easily replaceable. In someembodiments, if the fuse 404 short circuits and the switch-controlledVAR source 400 is disconnected from the power distribution network, thepower delivered to the residential and/or commercial loads may not beinterrupted.

The inductor 406 and resistor 408 may act as an L-R snubber to controlpeak inrush currents (e.g., during startup conditions) and to manageresonance. In some embodiments, the inductor 406 and resistor 408 mayprevent wear on the capacitor 412 and/or the other circuits of theswitch-controlled VAR source 400 caused by changes in voltage or powerreceived from the line 402 and/or activation or deactivation of theswitch-controlled VAR source 400.

Those skilled in the art will appreciate that, in some embodiments, theinductor 406 and resistor 408 may reduce susceptibility of the capacitor412 to harmonic resonance. In various embodiments, the switch-controlledVAR source 400 does not comprise the inductor 406 and/or the resistor408.

The capacitor 412 may be any capacitor configured to compensate forreactive power (e.g., VARs). In various embodiments, the relay 414and/or the semiconductor switch 416 may form a switch that completes thecircuit thereby allowing the capacitor 412 to influence reactive powerof the network. In one example, if the relay 414 is open and the triac420 (of the semiconductor switch 416) is deactivated, the capacitor 412may be a part of an open circuit may, therefore, have no effect on thepower distribution grid or the load.

The resistor 410 is an optional bleed resistor. In some embodiments,when the capacitor is disabled or otherwise disconnected by the switch(e.g., via relay 414 and/or semiconductor switch 416), the resistor 410may potentially receive energy from the capacitor 412 thereby allowingthe energy state of the capacitor 412 to decrease.

The relay 414 may be used to reduce losses when the semiconductor switch416 is active. The semiconductor switch 416 may be used to provideprecise and fast response at turn on and turn off. Those skilled in theart will appreciate that any appropriately tested relay (e.g., a testedelectromechanical relay) may be used.

The triac 420 of the semiconductor switch 416 is a gate-controlledthyristor in which current is able to flow in both directions. The relay414 and/or the triac 420 may perform as one or more switches. Forexample, the controller 426 may open the relay 414 and deactivate thetriac 420 to create an open circuit to disconnect the capacitor 412.

Those skilled in the art will appreciate that any switch may be used.For example, a switch S, such as an IGBT, thyristor pair, orthyristor/diode arrangement may also be used. In another example, amosfet or IGBT may be used with a diode in parallel to control thecapacitor 412.

Those skilled in the art will appreciate that the relay 414 and thetriac 420 may work together to preserve the life of all or some of thecomponents of the switch-controlled VAR source 400. The controller 426may be configured to control the relay 414 and the triac 420 to switchoff the circuit in a manner that avoids transients or other undesiredpower characteristics that may impact the lifespan of the circuit. Forexample, the controller 426 may ensure that the relay 414 is open (e.g.,instruct the relay 414 to open if the relay 414 is closed) beforeinstructing the triac 420 to deactivate (e.g., ½ cycle later). Thisprocess may prevent sparking or arcing across the relay 414 and,further, may preserve the life of the relay 414. In some embodiments,the triac 420 may be switched on and, after a sufficient delay, therelay 414 may be closed. The controller 426 may then instruct the relay414 to open thereby protecting the one or more components of thecircuit.

In various embodiments, the switch-controlled VAR source 400 comprisesthe relay 414 but not the semiconductor switch 416. In one example, thecontroller 426 may instruct the relay 414 to open or close therebyenabling or deactivating the capacitor 412. In other embodiments, theswitch-controlled VAR source 400 comprises the semiconductor switch 416but not the relay 414. The controller 426 may similarly control thetriac 420 to enable or disable the capacitor 412.

The optional resistor 418 may be a negative temperature coefficient(NTC) resistor or thermistor. The NTC resistor 418 is a type of resistorwhose resistance may vary with temperature. By controlling the NTCresistor 418, the triac 420 may be activated or deactivated withoutwaiting for a zero voltage crossing of the AC power from the line 402allowing insertion of the VAR source with minimal delay. For example,without the NTC resistor 418, the triac 420 may only be activated whenAC voltage crosses zero volts. The NTC resistor 418 may be configuredsuch that the triac 420 may be activated at any point with little or noundesirable effect (e.g., minimal or reduced inrush).

Resistors 422 and 424 may attenuate the signal from the line 402 to bereceived by the controller 426.

The controller 426 may be configured to determine a proximate voltagebased on the voltage of line 402 and may enable or disable the capacitor412. In various embodiments, the controller 426 is a processor such as amicroprocessor and/or a Peripheral Interface Controller (PIC)microcontroller that may detect voltage of the feeder 402.

In some embodiments, based on the voltage, the controller 426 maycontrol the relay 414 and/or the triac 420 to open or close the circuitthereby enabling or disabling the capacitor 412. For example, if thevoltage detected is not desirable, the controller 426 may enable thecapacitor 412 by commanding the triac 420 to activate and/or the relay414 to close. The capacitor 412 may then compensate for reactive power(e.g., regulate network voltage).

Those skilled in the art will appreciate that there may be a delay inthe response of relay 414 (e.g., the relay 414 may be anelectromechanical relay that is slow to react when compared to the triac420). In this example, the command to open the relay 414 may be sent inadvance of the command to deactivate the triac 420.

One of the most common failure mechanisms for capacitors on the grid isovervoltage. In some embodiments, the relay 414 and triac 420 may bedeactivated when overvoltage is detected thereby protecting thecapacitor(s).

In case of plurality of individual VAR sources inside a single unit, theusage of the switch controlled individual VAR sources will be uniformlydistributed over time. The decision to turn on an specific VAR sourcewill be determined by the on-board processor based on historicaloperational data. The VAR source which has been used the least amount oftime will be given preference over the ones which have been used more.This method ensures that no single VAR source will be exercised morethan others thereby improving reliability and life of the unit.

The controller 426 may delay activation of the switch (e.g., relay 414and semiconductor switch 416). In various embodiments, a multitude ofswitch-controlled VAR sources 400 which react to voltages within a powergrid. In order to prevent infighting among the switch-controlled VARsources 400, one or more of the devices may delay enabling or disablingthe VAR compensation component (e.g., capacitor 412). In variousembodiments, the controller of each switch-controlled VAR source 400includes a different delay. As a result, each switch-controlled VARsource 400 may activate the switch to regulate voltage at a differenttime thereby giving each device time to detect voltage changes that mayresult from one or more switch-controlled VAR sources 400.

Those skilled in the art will appreciate that the delay may be setduring manufacture of the switch-controlled VAR source 400 or may beuploaded from a centralized communication facility. The delay may berandomly set for each different switch-controlled VAR source 400.

The power supply unit (PSU) may adapt the power to be suitable to thecontroller 426. In some embodiments, the controller 426 is supplied frompower supplied by the line 402, batteries, or any other power source.The PSU 428 may be any power supply.

Although FIG. 4a depicts the line coupled to the resistor 422 as beingon the unprotected side of the fuse 404, those skilled in the art willappreciate that the fuse 404 may protect the controller 426 and PSU 428.For example, the resistor 422 may be coupled to the line 402 via thefuse 404. In particular, the fuse 404 may be connected in series with athermal fuse 404 a, which in turn may be thermally coupled to a metaloxide varistor (MOV) 407 to protect the individual VAR source 400against any overvoltage. In the event of an overvoltage, the MOV 407will clamp the voltage. If the event persists for a longer duration, theMOV 407 will overheat and cause the thermal fuse 404 a to open up. Thisway, the individual VAR source 400 is protected from catastrophicfailures. Further, isolation of the individual VAR source 400 (shouldfailure occur) allows for the normal operation of other sources, ifpresent in the unit, thereby ensuring high reliability of the unit.

In various embodiments, the switch-controlled VAR source 400 may operateboth dynamically and autonomously to regulate voltage and/or compensatefor grid faults. Those skilled in the art will appreciate that theswitch-controlled VAR source 400 may adjust reactive power and thus thenetwork voltage based on detected voltage without detecting or analyzingcurrent. In some embodiments, load current information can be derivedfrom an additional current sensor, or from the smart meter.

In some embodiments, the switch-controlled VAR source 400 may comprisean inductor which may be used to adjust voltage. For example, one ormore inductors may be in place of capacitor 412. In another example, oneor more inductors may be in parallel with the capacitor 412. Theinductor(s) may be coupled to the fuse 404 (or a different fuse) and maybe further coupled to a separate switch. For example, the inductor(s)may be coupled to a relay in parallel with a triac (or mosfet or IGBT)which may perform switching similar to the relay 414 and thesemiconductor switch 416. The controller 426 may enable the inductor anddisable the capacitor 412 by enabling one switch and creating an opencircuit with the other. Similarly, the controller 426 may disable theinductor and enable the capacitor 412 or, alternately, disable both.Those skilled in the art will appreciate that the triac associated withthe inductor may also be coupled to an NTC resistor to allow the triacto be deactivated at any time.

The switch-controlled VAR source 400 may be shunt-connected to the powerdistribution grid. In one example, the switch-controlled VAR source 400is coupled in shunt via conductive lines 402 and 430 at or proximate toa residence or other commercial load. A shunt connection may be theconnection of components within a circuit in a manner that there aremultiple paths among which the current is divided, while all thecomponents have the same applied voltage.

In one example, a feed line may extend from a transformer to one or moreloads (e.g., residences). The feeder may also be coupled with aswitch-controlled VAR source 400 in shunt. In some embodiments, if theswitch-controlled VAR source 400 fails or was otherwise inoperative, thedelivery of power by the power distribution grid is not interruptedbecause of the shunt connection (e.g., even if the connection to theswitch-controlled VAR source 400 became an open circuit, there may be nointerruption of power between the transformer and the one or more loadsalong the feed line).

In various embodiments, the switch-controlled VAR source 400 may becollocated inside or with a utility meter (e.g., smart meter), so thatinstallation can be piggybacked, saving the utility in totalinstallation and reading costs. The switch-controlled VAR source 400 mayleverage a communication link inside a smart meter to communicate withthe utility, take VAR dispatch or voltage set-point commands, and/orinform the utility of malfunction. Multiple switch-controlled VARsources 400 may be collocated in a common housing and can be mounted onanother grid asset, such as a pole-top or pad-mount transformer. Thismay allow lower cost VAR compensation, reduce the cost of acommunication link, and allow additional value to be derived, such asassessing status and life expectancy of the asset.

In various embodiments, a plurality of switch-controlled VAR sources mayeach comprise a communication module. A communication module is anyhardware configured to communicate wirelessly or by wire with one ormore digital devices or other shunt-connected, switch-controlled VARsources. The communication module may comprise a modem and/or anantenna.

One or more of the switch-controlled VAR sources may receive one or moreset points with which to compare against voltage to assist in thedetermination to engage the VAR compensation component. A set point maybe a predetermined value to improve voltage regulation. The processor ofswitch-controlled VAR source may determine whether to adjust voltagebased on the comparison of the proximate voltage to the set points.Those skilled in the art will appreciate that the set points may bedifferent for different switch-controlled VAR sources.

For example, the switch-controlled VAR source may compare detectedvoltage of a feeder (e.g., proximate voltage) to one or more set pointsto make the determination of whether to activate the capacitor based onthe comparison. For example, if the detected voltage is higher than apreviously received set point, the switch-controlled VAR source maydisable an otherwise active capacitor to reduce voltage. Alternately, ifthe voltage is lower than a previously received set point, theswitch-controlled VAR source may capacitor in order to increase voltage.

In some embodiments, a communication facility may dispatch and/or updateone or more set points. The switch-controlled VAR sources maycommunicate via a cellular network, power line carrier network (e.g.,via the power grid), wirelessly, via near-field communicationstechnology, or the like. The communication facility may update setpoints of any number of switch-controlled VAR sources at any rate orspeed. For example, the communication facility may update set pointsbased on changes to the grid, power usage, or any other factors.

In some embodiments, one or more of the switch-controlled VAR sourcesmay both receive and provide information. For example, one or more ofthe switch-controlled VAR sources may provide voltage information,current information, harmonic information, and/or any other informationto one or more communications facilities (e.g., digital devices).

The information detected, received, or otherwise processed by one ormore of the switch-controlled VAR sources may be tracked and assessed.For example, voltage and/or other power information may be tracked bythe VAR source or a centralized facility to determine usage rates andidentify inconsistent usage. A history of expected usage may bedeveloped and compared to updated information to identify changes thatmay indicate theft, failure of one or more grid components, ordeteriorating equipment. In some embodiments, one or moreswitch-controlled VAR sources may provide information to monitor agingequipment. When changes to voltage or other information indicatesdeterioration or degradation, changes, updates, or maintenance may beplanned and executed in advance of failure.

Those skilled in the art will appreciate that the controller of theswitch-controlled VAR source may enable or disable an inductor. In someembodiments, as discussed herein, the switch-controlled VAR source maycomprise an inductor and a capacitor in parallel. In some examples,based on the comparison of the detected voltage to one or more receivedset points, the controller of the shunt-connected, switch-controlled VARsource may enable or disable the inductor and the capacitorindependently.

FIG. 4b is a graph that depicts activating the semiconductor switchrelative to the relay to engage VAR compensation in some embodiments. Asdiscussed herein, when activating the switch-controlled VAR source 400,the controller 426 may be configured to activate the triac 420 prior toactivating the relay 414. In some embodiments, the controller 426 mayactivate the relay 414 following a predetermined delay. The delay may beany delay. In one example, the controller 426 may receive apredetermined delay (e.g., as software or firmware) during calibrationor installation either before or after manufacture of theswitch-controlled VAR source 400.

As depicted in FIG. 4b , the triac 420 may be activated when the voltageis low and/or the capacitive current is approximately 0. After a delaywhich may be, for example, approximately a cycle, the relay 414 may beclosed. Those skilled in the art will appreciate that, with the NTCresistor 418, the triac 420 may be activated at any time. Further, therelay 414 may be closed at any time after the triac 420 is active (i.e.,the delay may be any length of time).

FIG. 4c is a graph that depicts deactivating the semiconductor switchrelative to the relay 414 to disengage VAR compensation in someembodiments. As discussed herein, when deactivating theswitch-controlled VAR source 400, the controller 426 may be configuredto ensure that the relay 420 is closed prior to deactivating the triac420. The controller 426 may subsequently deactivate (open) the relay420. In some embodiments, the controller 426 may deactivate the relaytriac 414 following a predetermined delay. The delay may be any delaywhich may be software or firmware received during calibration orinstallation.

As depicted in FIG. 4c , the relay 420 may be closed at any time. Insome embodiments, the controller 426 confirms that the relay 420 isclosed. If the relay 420 is open, the controller 426 may control therelay 420 to close. After a delay (e.g., after approximately a cycle orany time), the controller 426 may deactivate the triac 420. Thoseskilled in the art will appreciate that the triac 420 may be deactivatedat any point. It should be further noted that the controller 426 maycontrol the relay 414 to open after the triac 420 is activated. In someembodiments, the controller 426 controls the relay 414 to open after apredetermined delay. The delay may be equal or not equal to the delaybetween closing the relay and deactivating the triac 414.

FIGS. 5a and 5b are graphs 500 and 508 that depict a desired voltagerange in relation to set points in some embodiments. In variousembodiments, a switch-controlled VAR source may comprise a single setpoint 502 (e.g., 240 volts). The switch-controlled VAR source may beconfigured to adjust voltage (e.g., through controlling the VARcompensation component) by comparing the detected voltage to the setpoint 502. Threshold 504 and 506 may identify an allowed voltage range(e.g., +/−2 volts) before the switch-controlled VAR source may enable ordisable the VAR compensation component.

Those skilled in the art will appreciate that the thresholds 504 and 506may be equal or unequal. Further, the thresholds 504 and 506 may changeover time (e.g., through an algorithm that changes based on time of day,season, temperature, voltage, current, rate of change in detectedvoltage, or the like).

FIG. 5b is a graph depicting voltage over time and identifying setpoints 510 and 512 in some embodiments. Set points 510 and 512 bracketthe desired “ideal” voltage (e.g., 240 volts). In various embodiments, aswitch-controlled VAR source may detect a proximate voltage and comparethe detected voltage to set points 510 and 512. If the voltage is higherthan set point 510 or lower than set point 512, the switch-controlledVAR source may enable/disable a VAR compensation component or otherwiseregulate the voltage to make corrections. Although the impact of oneswitch-controlled VAR source may not change the network voltagesignificantly, multiple VAR sources operating autonomously to change thenetwork voltage may regulate the voltage over multiple points. As such,a limited change by many devices may create significant efficiencies andimprovements in distribution with limited additional cost.

In various embodiments, one or more of the switch-controlled VAR sourcesdo not have communication modules but rather may comprise set pointspreviously configured at manufacture. In other embodiments, one or moreof the switch-controlled VAR sources comprise communication modules and,as a result, set points may be altered or updated by otherswitch-controlled VAR sources or one or more communication facilities.

In some embodiments, one or more of the switch-controlled VAR source maycomprise regulation profiles. A regulation profile may comprise a policythat changes one or more set points based on time, proximate conditions,or usage in order to improve conservation. If usage is likely to spike(e.g., based on heat of the day, business loads, residential loads, orproximity to electric car charging facilities), a regulation profile mayadjust the set points accordingly. As a result, set points may bechanged depending upon sensed usage, voltage changes, time of day, timeof year, outside temperature, community needs, or any other criteria.

Those skilled in the art will appreciate that one or more of theswitch-controlled VAR sources may receive regulation profiles at anytime over the communications modules. In some embodiments, one or moreof the switch-controlled VAR sources may not comprise a communicationmodule but may still comprise one or more regulation profiles which mayhave been previously configured.

FIG. 6 is a flow chart for voltage regulation by a switch-controlled VARsource in some embodiments. In step 602, the switch-controlled VARsource may receive a first set point. In some embodiments, theswitch-controlled VAR source comprises a communication module that mayreceive the set point from a digital device (e.g., wirelessly or througha communication module of a smart meter), from another shunt-connected,switch-controlled VAR source (e.g., through near field communication),power line carrier communication, or the like. The set point mayactivate the switch-controlled VAR source to enable VAR compensation or,in some embodiments, the set point may be a voltage set point which maybe compared to a detected proximate voltage.

In some embodiments, the utility may include a VAR source server orother device configured to communicate with different VAR sources (e.g.,via WiFi, cellular communication, near field communication, wired, orpower line carrier). In various embodiments, the VAR source server maycommunicate with one or more other servers to communicate with the VARsources. For example, the VAR source server may communicate throughsmart meters or servers that communicate with smart meters. One or moresmart meter may comprise a VAR source or otherwise communicate with oneor more VAR sources.

The first set point (e.g., a voltage set point) may be a part of aregulation profile. In one example, a plurality of regulation profilesmay be received by the switch-controlled VAR source either duringmanufacture or through a communication module. Each regulation profilemay comprise one or more different set points to improve powerdistribution and/or efficiency based on a variety of factors (e.g., timeof day, history of usage, type of load, green energy production, and thelike). In various embodiments, the processor of the switch-controlledVAR source may switch regulation profiles based on detected voltage,rate of change of voltage, communication with other switch-controlledVAR sources, communication with a VAR source server, temperature, timeof day, changes to the grid or the like. Once implemented from theregulation profile, the processor of a switch-controlled VAR source willcontinue to detect proximate voltage and compare the voltage to the newset point(s) in order to determine whether a VAR compensation componentshould be enabled or disabled.

In step 604, the controller 426 (i.e., processor) detects proximatevoltage at the edge of the network (e.g., near a load of the powergrid). Proximate voltage is the voltage received from line 402 (e.g.,the voltage at the point the line 402 is coupled to a feeder line orgrid asset. The proximate voltage may be the voltage of where theshunt-connected, switch-controlled VAR source 400 is coupled in thepower distribution grid at the time of voltage detection.

In some embodiments, the switch-controlled VAR source may detect voltagethrough another switch-controlled VAR source or a grid asset. In someembodiments, a smart meter, transformer, or other power device maydetect voltage. The switch-controlled VAR source may receive thedetected voltage from the other device or intercept the detected voltageat or during transmission.

In step 606, the controller 426 may compare the detected proximatevoltage to any number of set points to determine if the VAR compensationcomponent may be enabled or disabled. As discussed herein, thecontroller 426 may control a switch (e.g., relay and/or semiconductorswitch) to enable or disable one or more capacitors and/or one or moreinductors based on the comparison. Those skilled in the art willappreciate that the determination to enable or disable the VARcompensation component may be made by the processor of theswitch-controlled VAR source as opposed to a centralized facility. Thedetermination may be made autonomously and independent of otherswitch-controlled VAR sources.

Through the operation of any number of switch-controlled VAR sourcesoperating to regulate voltage within the desired range, voltageregulation of the network may be achieved. Further, the voltage rangemay be flat and capable of dynamically responding to changes along oneor more distribution lines and/or feeders.

In step 608, the controller 426 may delay switching the VAR compensationcomponent for a predetermined time. As discussed herein, in order toavoid infighting between any number of switch-controlled VAR sources,one or more of the switch-controlled VAR sources may delay switching fora predetermined time. The time of delay may be different for differentswitch-controlled VAR source. For example, even if a firstswitch-controlled VAR source detects the need to regulate voltage, thefirst switch-controlled VAR source may wait until after a secondswitch-controlled VAR source has made a similar determination andenabled VAR compensation. The first switch-controlled VAR source maydetect the change in the network and make another determination whetherto further enable additional VAR compensation. As a result, multipleswitch-controlled VAR source may not constantly correct and re-correctchanges in network voltage caused by other switch-controlled VARsources.

The delay time may be updated by the VAR source server, otherswitch-controlled VAR sources, or be a part of the regulation profile(e.g., which may comprise multiple different delay times depending onthe need). In some embodiments, if detected voltage is changing at asubstantial rate, the delay time may be accelerated. Those skilled inthe art will appreciate that there may be many different ways toprovide, update, and/or alter the delay time of a switch-controlled VARsource.

In step 610, after detecting and determining a need to change thenetwork voltage and waiting the delay time, the switch-controlled VARsource may again detect any changes to the voltage and compare thechange against one or more of the set points. If there remains adecision in step 612 that is consistent with the previous determinationin step 606 (e.g., that the VAR compensation component should be enabledor disabled), then the switch-controlled VAR source may adjust thenetwork voltage by engaging a switch to enable or disable the VARcompensation component.

In one example, if the proximate voltage is below a first set point, thecontroller 426 may control the relay 414 and the triac 420 to eitherform the connection to the line 402 or to confirm that the relay 414 isclosed and/or the triac 420 is enabled. If the proximate voltage isabove the second set point, the controller 426 may control the relay 414and the triac 420 to either open the connection to the line 402 or toconfirm that the relay 414 is open and/or the triac 420 is disabled.

In some embodiments, each of the plurality of shunt-connected,switch-controlled VAR sources may increase leading volt-ampere reactiveif the set point is higher than the detected proximate voltage anddecrease leading volt-ampere reactive if the set point is lower than thedetected proximate voltage.

In some embodiments, the controller 426 may enable or disable aninductor based on the comparison of the detected proximate voltage tothe set points. For example, based on the comparison, the controller 426may disable the capacitor and enable an inductor (e.g., the controller426 may control the relay 414 the triac 520 to create an open circuit todisable the capacitor while controlling another relay and another triacto enable the inductor to regulate voltage).

In various embodiments, voltage may be tracked over time. In someembodiments, the controller 426 may track the detected proximate voltageover time and provide the information to another switch-controlled VARsource and/or a digital device. For example, one switch-controlled VARsource may be in communication with any number of otherswitch-controlled VAR source (e.g., in a pole top enclosure). The one ormore switch-controlled VAR sources may be a part of any grid asset suchas a substation or transformer.

In some embodiments, the tracked detected voltage may be assessed and/orcompared to a voltage history. The voltage history may be a history ofpast usage or may indicate an expected usage. In various embodiments,the controller 426 or a digital device may detect a failing grid assetbased on the comparison. For example, the expected output and/or inputof a grid asset may be determined and compared to the tracked detectedproximate voltage. If the currently detected proximate voltage and/ortracked detected proximate voltage are not within the expected range,the tracked detected proximate voltage may be reviewed to determine if agrid asset has failed or is deteriorating. As a result, deterioratingequipment that may need to be replaced or receive maintenance may beidentified and budgeted before performance significantly suffers therebyimproving efficiency in both power delivery and upkeep of thedistribution power grid.

Those skilled in the art will appreciate that potential theft may beidentified. In various embodiments, each switch-controlled VAR sourcemay detect and track voltage. The tracked voltage may be logged and/orprovided to a VAR source server (e.g., via the communication module orantenna of another digital device such as a smart meter). The VAR sourceserver may, for example, track voltage identified by all of theswitch-controlled VAR sources along a feeder line and compare thevoltage to consumption as tracked by the utility (e.g., via smartmeters). Based on the comparison, theft may be detected. Further, basedin part on the effect of any number of switch-controlled VAR sources,the theft may be localized for further investigation.

As suggested herein, massively distributed dynamically controllable VARsource strategy leverages other costs that a public utility is alreadybearing. For example, a switch-controlled VAR source may be locatedinside a smart meter or may be co-located with a smart meter so that theinstallation can proceed concurrently with meter installation orreading/servicing. These meters sense voltage and current to calculatethe power consumption of the load, and have communications to relay theinformation to a central data repository. The cost of installing theseis already built into the meter cost.

A simple communication mechanism with the meter may allow communicationbetween the meter and the switch-controlled VAR source (e.g., forreporting to the utility on status, receiving set points, receivingdelay times, and/or for taking commands to activate). In someembodiments, the load current measurement inside the smart meter may becommunicated to the switch-controlled VAR source for use in thedetermination for voltage regulation.

In various embodiments, a meter switch-controlled VAR source may be verycompact and ultra low-cost. In some embodiments, a typical rating may be240 VARs at 240 volts, corresponding to 1 Ampere of capacitive current.This may be approximately the VAR drop across the leakage impedance of a5% impedance transformer supplying 5 kW to a customer. Utility networksand asset loading calculations may be done on a statistical basis,assuming a load diversity factor. If all the meters (e.g., 10,000) on adistribution circuit have switch-controlled VAR sources, then there maybe 2.5 MVARs of dynamically controllable VARs on that line, deployed ona per phase basis. Raising the compensation per switch-controlled VARsource to 500 VARs, for example, may only raise cost marginally, but mayprovide 5.0 MVARs of dynamic VAR compensation.

In various embodiments, the switch-controlled VAR source may beintegrated into or be alongside any utility asset, such as a pole-mounttransformer or lighting pole. As discussed herein, communicationcapability is not a requirement for switch-controlled VAR sourceoperation, but may augment the ability to take dispatch instructions andto communicate status to the utility. A possible implementation would beto bundle multiple switch-controlled VAR sources into a common housingand locating the bundle within or proximate to a transformer supplyingmultiple residential or commercial loads. The bundle may be connected tothe transformer on the low-voltage side thereby minimizing or reducingrequirements for BIL management on the switch-controlled VAR sources.

Those skilled in the art will appreciate that the bundling may allowintegration of a single communication module with multipleswitch-controlled VAR sources, thereby allowing greater cost savings.This class of device may be measured in cost as a ratio of the dollarsof cost of the actual device to the kiloVARs delivered ($/kVAR). Thisbundling may also allow the use of a single power supply and controllerand provide reliable information on the switching behavior of thedifferent switch-controlled VAR source.

In a bundled unit, it may be possible to minimize or reduce impact ofharmonics on the grid. This implementation may maintain the basicfeatures of the single user units, however, the bundle may provide morevalue to utility customers by integrating current and temperaturemeasurement into the unit, using transformer loading and temperatureexcursions to calculate impact on transformer life, and/or communicatingtransformer status to the utilities. The bundled switch-controlled VARsource implementation, particularly when located in close proximity topole-top or pad-mount transformers as conventionally used in the utilityindustry, may offer high value to the utility by performing dynamicvolt-VAR optimization, and serving as an asset monitor for the millionsof transformers located on the distribution network.

In various embodiments, in order to avoid multiple switch-controlled VARsources from adjusting and readjusting the reactive power based onchanges perceived by other switch-controlled VAR sources, one or morecontrollers may activate or deactivate different switch-controlled VARsource based on a different detected voltage.

The switch-controlled VAR source may perform reactive power compensationbased on measured line voltage and not load or line current. As aresult, the switch-controlled VAR source may not perform power factorcorrection. Power factor compensation may look at the line current andvoltage to assess the level of correction required and may operate tobring customer load power factor to unity. Power factor correction maynot manage reactive power for grid voltage regulation. Those skilled inthe art will appreciate that power factor correction is often used toreduce penalties, and may reduce energy supplied by the utility to someextent (if loads have a significant lagging power factor). In otherembodiments, the switch-controlled VAR source may detect current (e.g.,via a meter, grid asset, or assessment by the controller 524) andperform power factor correction in addition to voltage regulation usinga weighting algorithm.

FIG. 7 is a time sequence of events of network regulation with twoswitch-controlled VAR sources in some embodiments. In variousembodiments, the first and second switch-controlled VAR sources may beproximate to each other (e.g., coupled to the same or related feederline). Changes to voltage caused by one switch-controlled VAR source maybe detected and reacted to by the other switch-controlled VAR source. Asa result, to avoid infighting (e.g., constant correcting andre-correcting voltage in view of other switch-controlled VAR sourceactions), the switching process for one or more of the switch-controlledVAR sources may be delayed by a different delay time. As a result, evenif the first switch-controlled VAR source originally determined toenable the VAR compensation component based on the detected voltage, thefirst switch-controlled VAR source may wait the delay time therebygiving the second switch-controlled VAR source an opportunity to correctvoltage. If the action of the second switch-controlled VAR source wassufficient, then the first switch-controlled VAR source may detect thechange and not perform any switching action.

In step 702, the first switch-controlled VAR source detects a firstvoltage proximate to a first edge of the network. In some embodiments,the first switch-controlled VAR source detects a voltage at a particularload on the low power side of a transformer. In step 704, the firstswitch-controlled VAR source may compare the first proximate voltage toa set point to determine if the VAR compensation component of the firstswitch-controlled VAR source should be enabled. In step 706, theswitch-controlled VAR source may delay switching to engage the VARcompensation component for a first predetermined time (i.e., for a firstdelay).

In step 708, the second switch-controlled VAR source detects a secondvoltage proximate to a second edge of the network. In some embodiments,the second switch-controlled VAR source detects a voltage at aparticular load on the low power side of a transformer. In one example,both the first and second switch-controlled VAR source may be coupled tothe same feeder line and/or on the same side of the same transformer. Instep 710, the second switch-controlled VAR source may compare the secondproximate voltage to a set point to determine if the VAR compensationcomponent of the second switch-controlled VAR source should be enabled.In step 712, the switch-controlled VAR source may delay switching toengage the VAR compensation component for a second predetermined time(i.e., for a second delay).

The first and second delay may be for different periods of time. As aresult, each switch-controlled VAR source may delay acting on thecomparison of the detected proximate voltage to one or more set pointsuntil other switch-controlled VAR sources have had an opportunity tocorrect voltage of the network. If, after the predetermined time, theinitial determination is still necessary (e.g., the proximate voltagehas remained unchanged or still outside of the set point(s) afterexpiration of the delay time), then a switch-controlled VAR source maycontrol a switch to engage or disengage the VAR compensation component.

In various embodiments, delays may be used to avoid infighting betweentwo or more switch-controlled VAR sources. The delays may be updatedand/or communicated by another digital device (e.g., wirelessly, overpower line carrier, or via a smart meter).

As discussed herein, the delay time may be altered based on conditionsof the power network. For example, if the rate of change of voltage,current, or any power characteristic is significant, the delay time maybe shortened or extended. In some embodiments, there are different delaytimes for different switch-controlled VAR sources, however, all of thedelay times may be changed in the similar manner (e.g., shortened orextended) under similar conditions.

In step 714, the second switch-controlled VAR source detects proximatevoltage after the second delay time (e.g., after the secondpredetermined delay). In various embodiments, the switch-controlled VARsources detect proximate voltage at predetermined times or continuously.Once the delay is expired, the controller of the secondswitch-controlled VAR source may retrieve the last detected voltage ordetect voltage of the line. In step 716, the second switch-controlledVAR source determines whether to enable VAR compensation based oncomparison of the last detected proximate voltage to one or more setpoints.

In step 718, if, based on the comparison, the second switch-controlledVAR source determines to enable the VAR compensation component, thesecond switch-controlled VAR source may adjust the network voltage(e.g., by regulating VAR).

In various embodiments, the first switch-controlled VAR source maycontinue the delay before switching the related VAR compensationcomponent. The first switch-controlled VAR source may detect a change involtage caused by the action of the second switch-controlled VAR source.If, after the first delay, the newly detected proximate voltage is stilloutside a range established by one or more set points, the firstswitch-controlled VAR source may engage the VAR compensation component.If, however, after the delay, the action of the second switch-controlledVAR source improves network voltage (e.g., the newly detected voltage iswithin a range of the one or more set points), the firstswitch-controlled VAR source may not take further action.

In step 720, the first switch-controlled VAR source detects proximatevoltage after the first delay time (e.g., after the first predetermineddelay). In one example, once the delay is expired, the controller of thefirst switch-controlled VAR source may retrieve the last detectedvoltage or detect voltage of the line. In step 722, the firstswitch-controlled VAR source determines whether to enable VARcompensation based on comparison of the last detected proximate voltageto one or more set points.

In step 724, if, based on the comparison, the first switch-controlledVAR source determines to enable the VAR compensation component, thefirst switch-controlled VAR source may adjust the network voltage (e.g.,by regulating VAR).

Those skilled in the art will appreciate that the voltage set points maybe preconfigured. In some embodiments, one or both switch-controlled VARsources may comprise communication module(s) configured to receive setpoint(s). In one example, a switch-controlled VAR source may receive newset points that may replace or supplement previously received and/orpre-existing set points.

Although only two switch-controlled VAR sources are discussed regardingFIG. 7, those skilled in the art will appreciate that there may be anynumber of switch-controlled VAR sources working to adjust the networkvolt ampere reactive (e.g., each may have different delays to preventinfighting).

FIG. 8 is a graph that depicts a typical voltage profile at variousnodes in the prior art. Colored dots represent various times of the day.With the prior art's approaches, a VVO or CVR solution is limited by thehighest and lowest voltage nodes.

FIG. 9 is a graph that depicts relatively flat voltage profile atvarious nodes in some embodiments realized with 240 switch controlledVAR sources operating to regulate the voltage along the edge of thedistribution feeder. Edge of Network Voltage Optimization (ENVO) asdiscussed herein may be achieved through dynamic, autonomous actions ofmultiple switch-controlled, VAR sources at or near the edge of thenetwork. The switch-controlled, VAR sources may react automatically andautonomously (e.g., independent switching to enable or disable a VARcompensation component) to varying levels of loading on the feeder,maintaining the edge of network voltage all along the feeder within atight regulation band.

This regulation may be maintained automatically even as heavily loadedregions shift randomly and stochastically over the design range for thefeeder. In some embodiments, what results is a remarkably flat voltageprofile across all measured edge of network points which isunprecedented under current technology. The graph shows voltage withENVO that is relatively flat, voltage without ENVO that dropssignificantly, and a relatively flat voltage utilizing ENVO in CVR mode.The voltage spread is seen to reduce from +1-5% without compensation to+1-1% with ENVO when operated with the same feeder and the same load.

FIG. 10 is a graph that depicts a dynamic response of the ENVO system toline voltage changes (which can be caused by solar PV plants), as wellas to step changes in line loading in some embodiments. In both cases,the voltage across the entire line is seen to quickly stabilize,demonstrating the high speed response. It may be noted that the initialchanges to the lines beginning at time 0 and the changes to the linesafter time 2.5 are a part of the set up and deactivation of asimulation.

FIG. 10 shows the ability to implement CVR with ENVO compensation,realizing a flat and reduced voltage profile along the length of thefeeder. Coordinating with an LTC at the substation, it is seen that theedge of network voltage may be reduced by 3-6% (e.g., 4%) giving areduction of 3.2% of energy consumed under a typical CVR factor of 0.8.This level of performance is simply not possible with conventional VVCor VVO solutions in the prior art.

The ENVO system operation may not be generally impacted by networkconfiguration or by direction of power flows (e.g., from sporadic greenenergy generation), as are other VVO methods that rely on concentratedpositions of devices that may work for one configuration but notanother. As a result, network reconfiguration due to Fault DetectionIsolation and Restoration (FDIR) schemes may not negatively impact theENVO. Further, operation of tap changers may be simplified, as can theimplementation of CVR functionality due to the increased control of theedge of network voltage profile. Moreover, the ENVO system sources mayrespond rapidly (e.g., within or much less than a cycle such as equal orless than 16.6 ms), to system faults helping to avert cascading failuressuch as Fault Induced Delayed Voltage Recovery or FIDVR events.

While no communication is required to achieve a flatter voltage profilealong the entire length of the line, in various embodiments, inexpensiveslow-speed variable-latency communications may allow advanced functionssuch as VVO and CVR (e.g., through set points), without the complexityof current VVO systems, at a cost that is substantially lower. Further,significant opportunities may exist to leverage existing investments incommunications and other grid infrastructure to further reduce the totalcost of ownership.

In mature markets, such as in the US, the ENVO system may implement acost-effective distribution automation technology with a strong returnon investment (ROI). In some embodiments, the ability to dynamicallyand/or automatically compensate for line-voltage drops all along thefeeder allows building longer feeders, allows an increase in thecapacity of existing feeders, particularly in rural areas, andsignificantly reduces the number of tap changing regulators needed aswell as reduces the frequency of tap changes. It may also allow easierintegration of distributed generation resources and may counteract therapid voltage fluctuations caused by green energy generation (e.g.,unpredictable clouds or wind change).

FIG. 11a is another circuit diagram of a plurality of switch-controlledVAR sources that may be within or next to a pole top transformer or anygrid asset in some embodiments. FIGS. 1b -3 focus on different portionsof the circuit diagram of FIG. 11a . In various embodiments, anytransformer (e.g., pole top transformer), smart meter, meter, or gridasset may comprise one or more VAR sources. Each of a plurality of VARsources may make determinations and adjust voltage autonomously fromothers in the pole top transformer. In some embodiments, a plurality ofVAR sources may share any number of components, including, for example,a controller and/or a power supply unit.

In various embodiments, one or more controllers may control two or moreof the VAR sources in a pole top transformer to coordinate voltageadjustment. For example, a single controller may detect proximatevoltage, compare the voltage against one or more set points, determine avoltage adjustment, and determine which of the VAR sources should beenabled (or disabled) to achieve the desired effect and provide theappropriate commands.

In some embodiments, one or a subset of the VAR sources may comprise oneor more inductors in parallel with one or more capacitors. Those skilledin the art will appreciate that the inductor may be enabled whennecessary to adjust voltage. In other embodiments, there may any numberof inductors and any number of capacitors in any number of theshunt-connected, switch-controlled VAR sources.

FIG. 11a depicts a switch-controlled VAR source 1102, a plurality ofswitch-controlled VAR sources 1104, a controller 1106, and a powermodule 1108. The switch-controlled VAR source 1102 may be any one of theplurality of switch-controlled VAR sources 1104. The switch-controlledVAR source 1102 may be similar to the switch-controlled VAR source 400.The plurality of switch-controlled VAR sources 1104 may comprise anynumber of switch-controlled VAR sources. The controller 1106 may be amicroprocessor, PIC, or any processor. The power module 1108 may performvoltage detection and/or zero crossing threshold detection (ZCD).

Those skilled in the art will appreciate that the circuits depicted inFIG. 11 may be a part of any device or combination of devices and is notlimited to pole top transformers. For example, there may be a pluralityof switch-controlled VAR sources 1104, controllers 1106, and/or powermodules 1108 associated with any grid asset or as a standalone unit(e.g., coupled to a feeder line in shunt).

FIG. 11b depicts a switch-controlled VAR source 1102 in someembodiments. The switch-controlled VAR source 1102 may comprise a fuse,capacitor, harmonic sensor, zero voltage detection for ADC circuitry, Isense detection for ADC circuitry, and a relay circuit. Theswitch-controlled VAR source 1102 may be coupled to a feeder in shunt,adjust reactive power, and provide information (e.g., harmonicinformation, ZVD, and/or I sense signals) to the controller 1106. Thetriac and relay circuit may be controlled by signals from the controller1106.

In some embodiments, the harmonic sensor may detect harmonic resonancewhich may be subsequently reduced or eliminated. The I sense detectionfor ADC circuitry and zero voltage detection for ADC circuitry may beused to detect current, harmonics, and/or voltage which may allow thecontroller 1106 to better protect the circuit and make adjustments forvoltage regulation. The relay circuitry may be a part of the switch toenable or disable the capacitor.

FIG. 11c depicts a plurality of switch-controlled VAR sources 1104 insome embodiments. Each switch-controlled VAR source of FIG. 11c mayinclude similar or dissimilar components from the otherswitch-controlled VAR sources. For example, one or more of theswitch-controlled VAR sources may comprise an inductor in parallel witha capacitor. A single controller may control one or more of theswitch-controlled VAR sources.

FIG. 11d (and FIGS. 11d -1, 11 d-2, 11 d-3, and 11 d-4 which areexploded views of the corresponding sections/elements illustrated inFIG. 11d ) depicts a controller 1106 in some embodiments. The controller1106 may control any number of switch-controlled VAR sources 1104. Thecontroller may receive information (harmonic information, ZVD, and/or Isense signals) from one or more of the switch-controlled VAR sources anduse the information to control triacs, relays, and/or reduce harmonicresonance. For example, the controller 1106 may receive and makeadjustments based on voltage detection of only one of the plurality ofswitch-controlled VAR sources 1104. Although only one processor isdepicted in FIGS. 11a and 11d , those skilled in the art will appreciatethat there may be any number of processors coupled to any number ofswitch-controlled VAR sources.

FIG. 11e depicts power module 1108 comprising ADC circuitry and ZCDcircuitry coupled to the controller 1106 in some embodiments. The ADCcircuitry and ZCD circuitry may be coupled to the feeder and provideinformation and/or power to the controller 1106. The ADC circuitry andZCD circuitry may provide the controller 1106 power and/or informationregarding voltage. In some embodiments, the controller 1106 controls oneor more of the triacs of the plurality of the switch-controlled VARsources 1102 based on the zero crossing detection.

Those skilled in the art will appreciate that other circuit designs,components, and the like may perform similar functionality or performsimilar results and still be within the embodiments of the disclosuredescribed herein.

In some embodiments, a Distributed Controllable VAR Source (DCVS) thatintegrates a VAR source with various customer-located assets (e.g.,Smart Meters, electric vehicle chargers, demand response controllers,smart thermostats) is provided. As such, a cloud of distributed VARsources may be implemented.

FIG. 12 illustrates an exemplary power system 1200 including a VAR cloud1202 in some embodiments. In the illustrated example, the power system1200 comprises a primary distribution network 1201, a VAR cloud 1202, aSupervisory Control and Data Acquisition (SCADA) 1203, and a dataconcentrator 1204. The VAR cloud 1202 includes a cloud of DCVS 1-n1205-1214. The distribution network 1201 includes various power systemassets such as a capacitor bank, a Load Tap Changer (LTC), a LineVoltage Regulator (LVR), or other devices. The DCVS may work atdifferent locations including residential locations, commercial and/orindustrial locations, and/or service transformers. For example, theDCVS's 1205-1209 and 1212 are at residential locations, the DCVS 1213 isat commercial and/or industrial locations, the DCVS's 1207, 1210, and1214 are at service transformer locations, and the DCVS 1211 isintegrated with customer assets 1215 that may be at various locations.As illustrated, a large quantity (e.g., from 100,000 to several million)of DCVS's may be deployed per utility customer. Infrastructures thatsupport the operation of a power grid may be leveraged to gather datafrom and to manage the distributed VAR cloud and thereby provide newvalue streams to utility customers. For example, the data concentrator1204, a meter data management system, data historian, or other similarsystems or grid components may integrate the data flows and realizesignificant cost savings.

FIG. 13 is a block diagram of an exemplary distributed controllable VARsource (DCVS) 1300 in some embodiments. The illustrated DCVS 1300integrates a smart meter module 1301 and a DCVS module 1302. The smartmeter module 1301 comprises a DC power supply and conditioningsub-module 1304, a sensing and signal conditioning sub-module 1305, amemory sub-module 1306, a processor sub-module 1307, and a communicationsub-module 1308. The DC power supply and conditioning sub-module 1304 isconfigured to provide power to various sub-modules included in the smartmeter module 1301. The sensing and conditioning sub-module 1305 isconfigured to measure voltage across and/or current through the smartmeter module 1301. The sensing and conditioning sub-module 1305 may befurther configured to condition the signals that are measured such thatthe signals may be processed by the processor sub-module 1307. Theprocessor sub-module 1307 may be configured to determine variousparameters (e.g., instantaneous power, peak power, power factor, etc.)based on various measurements provided by the sensing and conditioningsub-module 1305. Various measurements and processing results may bestored in the memory 1306. The communication sub-module 1308 may beconfigured to receive and/or transmit data such as instructions (e.g., avoltage set point), various measurements (e.g., voltage, current, orpower factor), diagnostic information, timestamp, or any data related tothe operation of the DCVS 1300. The DCVS module 1302 may be coupled tothe smart meter module 1301. Various data (e.g., a voltage set point, avoltage, a current, a power factor, or a timestamp) may be exchangedbetween the DCVS module 1302 and smart meter module 1301 via acommunication interface. The DCVS 1300 may be configured to be coupledto a power supply 1303 such as an electric utility, a micro-grid, or apower supply bus. The DCVS 1300 may further comprise a surge protectionmodule that protects the smart meter module 1301 and the DCVS module1302.

The cost of integrating the DCVS module 1302 with the smart meter module1301 is only marginal. An effective VAR cloud that has tremendous VARsupport potential may be formed. As an example, if there are 1 millionDCVS installed on the utility network and all are integrated with 1 kVARDCVS modules and smart meter modules. The cost of integrating a DCVSwith a smart meter module is very small, for example, around 10% of thecost of the smart meter. Further, the VAR cloud formed may provide asupport capability of 1000 MVAR with unprecedented levels ofgranularity.

In some embodiments, the smart meter module 1301 and the DCVS module1302 are placed in a housing 1310, as illustrated. In some embodiments,the DCVS module 1302 is coupled to the smart meter module 1301 using acoupling mechanism such as a meter collar or external adjacentenclosure. The smart meter module 1301 and the DCVS module 1302 may bedeployed to and installed in a power system at the same time. As such,the cost of installation and commissioning may be leveraged. In variousembodiments, a DCVS 1300 is controlled using a distributed algorithm, asdescribed herein, that prevents fighting between adjacent units andstill provides fast dynamic responses. In further embodiments, anothermodule such as a home energy management module, a temperature managementmodule, an electric vehicle module may be configured to integrate a DCVStherein. These modules may be implemented similar to the smart metermodule 1301 as illustrated in FIG. 13 and various embodiments may bedeployed at different customer locations. Various embodiments mayprovide VAR controls at different levels. Moreover, processor sub-module1307 can determine which VAR compensation components of the plurality ofVAR sources are enabled and which VAR compensation components of theplurality of VAR sources are not enabled with the objective of uniformlydistributing number of operation and usage across the different VARsources to ensure long life of the components.

In various embodiments, a DCVS uses the hybrid switching strategies inwhich a semiconductor switch is coupled with a relay in parallel. Thesemiconductor switch (e.g., a triac or thyristor pair) provides highspeed switching and the relay ensures low losses. The line voltage andthe voltage across the semiconductor switch may be detected. The DCVSmay be turned on to provide VAR control when insertion of VARs isrequired and when the instantaneous voltage across the device is near azero value. The semiconductor switch may be further coupled to a NTC inseries. The NTC is configured to manage inrush currents that may flowdue to any residual voltages resulting from inexact sampling, harmonics,or other inaccuracies. The semiconductor switch may be turned on at anarbitrary time but losses may be higher, and coordination with the stateof the NTC may be necessary. When a DCVS includes low-loss capacitorsimplemented with the hybrid switching strategies, losses may be kept toless than 2 watts per kVAR of injection. As such, a VAR source (e.g., aDCVS module 1302) may be encased with a smart meter module in the samehousing.

When the semiconductor switch is conducting, the time taken for the NTCresistance to reach a predetermined value (e.g., a stable low value) ismeasured. It may require more time for a NTC to reach a stable low valueat colder ambient temperatures. The time may be monitored or the voltageacross the NTC may be monitored and only when it reaches a stable lowvalue, the relay coupled to the semiconductor switch is turned ON. Therelay may be turned ON at a predetermined time period which ensuresstable low value of the NTC under the entire operating temperature rangeinternal to the DCVS unit. The losses in the switches are reduced yetsub-cycle switching speeds are ensured. When turning off a DCVS, thesemiconductor switch is turned on and subsequently, the relay is turnedoff. A small overlap in the operation of the semiconductor switch andthe relay is ensured and a current conduction path is provided, whichavoids arcing or high energy dissipation across the relay and ensureslong life of the components. Once the relay is turned off, thesemiconductor switch may be turned off at a zero current crossing.

FIG. 14 is a control diagram of an example method of controlling a DCVSin some embodiments. Various embodiments implement a ‘randomizedtemporal droop’ strategy to prevent in-fighting among multiple DCVS'sdeployed on a system. A time constant of response for differentembodiments may be randomized, and a gain that decreases as the error isreduced may be used. In various embodiments, a DCVS that is closer tothe source of a disturbance may respond faster and more aggressivelythan a DCVS that is further from the source of the disturbance. As such,in-fighting between different DCVS's may be prevented by usingasymptotic settling through gains that get lower as the error isreduced. Accordingly, the overall system-level response times may belonger than individual unit response times.

As illustrated, at block 1402, a voltage difference is determined bycomparing the actual voltage of a DCVS measured to the voltage set pointof the DCVS. At block 1404, the absolute value of the voltage differenceis compared to a predetermined voltage threshold. If the voltagedifference exceeds the predetermined voltage threshold, no action istaken at block 1406. If the voltage difference does not exceed thepredetermined voltage threshold, a time constant of response t is setfor the DCVS. The time constant of response t may be randomized suchthat DCVS's in close proximity do not fight with each other. At block1410, a gain is determined and set for the DCVS. The gain may beproportional to the voltage difference to ensure asymptotic stabilityand convergence of the system. At block 1412, it is determined whetherthe voltage difference is large. If so, at block 1414, the voltagedifference is compared to the value zero. At block 1416, if the voltagedifference does not exceed the value zero, multiple VARs (which areexamples of DCVS's) or Qs are determined to be removed. At block 1418,if the voltage difference exceeds the value zero, multiple DCVS's aredetermined to inject VAR or Q. Referring again to block 1412, if thevoltage difference is determined not to be large, only the DCVS isdetermined to operate. At block 1420, the voltage difference is comparedto the value zero. At block 1422, if the voltage difference exceeds thevalue zero, the DCVS is determined to inject VAR or Q. At block 1424, ifthe voltage difference does not exceed the value zero, the VAR or Q isdetermined to be removed. It should be noted that the VAR provided by aDCVS may be leading or lagging.

FIG. 14b illustrates one specific example method of controlling a DCVS,based on the above-described method of FIG. 14a , in a scenario where aDCVS is integrated into a smart meter. As illustrated, at block 1402, avoltage difference is determined by comparing the actual voltage of aDCVS measured to the voltage set point of the DCVS. At block 1404, theabsolute value of the voltage difference is compared to a predeterminedvoltage threshold. If the voltage difference exceeds the predeterminedvoltage threshold, no action is taken at block 1406. If the voltagedifference does not exceed the predetermined voltage threshold, a timeconstant of response t is set for the DCVS. The time constant ofresponse t may be randomized such that DCVS's in close proximity do notfight with each other. At block 1410, a gain is determined and set forthe DCVS. The gain may be proportional to the voltage difference toensure asymptotic stability and convergence of the system. In contrastto the method of FIG. 14a , however, the next determination that is madeis to determine, at block 1420, whether the voltage difference isgreater than the value zero. At block 1422, if the voltage differenceexceeds the value zero, the DCVS is determined to inject VAR or Q. Atblock 1424, if the voltage difference does not exceed the value zero,the VAR or Q is determined to be removed. Again, the VAR provided by aDCVS may be leading or lagging.

Communication latencies do not limit the ability of a DCVS to respond todesired changes. When system configuration changes occur due to loss ofa line or other system fault, fast VAR responses are necessary. Atransmission fault can trigger a Fault Induced Delayed Voltage Recovery(FIDVR) event that can cause voltage collapse. For such disturbances, aDCVS may automatically provide the level of VARs needed to support thesystem during and through the fault. This automatic functionality may beachieved autonomously with no fast communication from a central commandto the distributed DCVS's. For example, for a utility with one millionDCVS's, each of which comprises a smart meter module and a DCVS modulewith a 1 kVAR VAR source. Accordingly, as much as 1000 MVAR ofdistributed dynamic VARs are available for grid support. Multi-variableoptimization may be achieved with a distributed VAR system. Depending onthe level of VAR resources for each DCVS, multiple optimizationfunctions may be simultaneously achieved. For example, secondary sidevoltage regulation at most nodes, primary voltage regulation, or controlof feeder level VARs may be achieved. In some embodiments, depending onthe level of granularity for VAR control at individual distributiontransformers, the power factor at individual transformers may also becontrolled. The voltage across the feeder may be independentlycontrolled from the VARs. Optimization strategies such as ConservationVoltage Reduction (“CVR”), peak demand management, or line lossminimization, even as voltage compliance requirements are met.

A cloud of VAR sources may provide local, regional and system levelbenefits. Locally, each VAR source may inject VARs to correct thevoltage moving it closer to the respective voltage set point. Inaddition, setting the voltage set point at the same value for all thedevices in a region, may allow the primary voltage to move substantiallytowards the same effective voltage set point. If a local VAR source hassufficient granularity and control range, the node to which the localVAR source is coupled may operate in a manner to improve the powerfactor closer to unity. By improving the primary voltage closer to thevoltage set point, the voltage profile may be improved even for thosenodes without any VAR sources connected. At a feeder level, if a voltagecontrol device such as a Load Tap Changer (LTC) or Line VoltageRegulator (LVR) is present, coordination of control between the LTCvoltage set point and the voltage set point for the VAR cloud, mayrealize independent decoupled control of the feeder voltage and the VARsmeasured at the substation. The LTC voltage set point and the VAR cloudset point may be regulated to achieve control of feeder, regional andlocal voltages as well as the VARs.

FIG. 15 is a block diagram of an exemplary digital device 1500. In someembodiments, the digital device 1500 may provide set points and/orprofiles to one or more switch-controlled VAR sources. The digitaldevice 1500 may also receive voltage and/or power tracking informationwhich may be used to track usage, identify potential theft, and/ormaintain grid assets. Further, in various embodiments, the digitaldevice 1500 may coordinate and/or control any number ofswitch-controlled VAR sources.

The digital device 1500 comprises a processor 1502, a memory system1504, a storage system 1506, a communication network interface 1508, anoptional I/O interface 1510, and an optional display interface 1512communicatively coupled to a bus 1514. The processor 1502 is configuredto execute executable instructions (e.g., programs). In someembodiments, the processor 1502 comprises circuitry or any processorcapable of processing the executable instructions.

The memory system 1504 is any memory configured to store data. Someexamples of the memory system 1504 are storage devices, such as RAM orROM. The memory system 1504 can comprise the ram cache. In variousembodiments, data is stored within the memory system 1504. The datawithin the memory system 1504 may be cleared or ultimately transferredto the storage system 1506.

The data storage system 1506 is any storage configured to retrieve andstore data. Some examples of the data storage system 1506 are firmwarememory, flash drives, hard drives, optical drives, and/or magnetic tape.In some embodiments, the digital device 1500 includes a memory system1504 in the form of RAM and a data storage system 1506 in the form offlash data. Both the memory system 1504 and the data storage system 1506comprise computer readable media which may store instructions orprograms that are executable by a computer processor including theprocessor 1502.

The communication network interface (com. network interface) 1508 can becoupled to a network (e.g., communication network 164) via the link1516. The communication network interface 1508 may support communicationover an Ethernet connection, a serial connection, a parallel connection,or an ATA connection, for example. The communication network interface1508 may also support wireless communication (e.g., 802.16 a/b/g/n,WiMax). It will be apparent to those skilled in the art that thecommunication network interface 1508 can support many wired and wirelessstandards.

The optional input/output (I/O) interface 1510 is any device thatreceives input from the user and output data. The optional displayinterface 1512 is any device that is configured to output graphics anddata to a display. In one example, the display interface 1512 is agraphics adapter. It will be appreciated that not all digital devices1500 comprise either the I/O interface 1510 or the display interface1512.

It will be appreciated by those skilled in the art that the hardwareelements of the digital device 1500 are not limited to those depicted inFIG. 15. A digital device 1500 may comprise more or less hardwareelements than those depicted. Further, hardware elements may sharefunctionality and still be within various embodiments described herein.In one example, encoding and/or decoding may be performed by theprocessor 1502 and/or a co-processor located on a GPU (i.e., NVidia).

The above-described functions and components can be comprised ofinstructions that are stored on a storage medium such as a computerreadable medium. The instructions can be retrieved and executed by aprocessor. Some examples of instructions are software, program code, andfirmware. Some examples of storage medium are memory devices, tape,disks, integrated circuits, and servers. The instructions areoperational when executed by the processor to direct the processor tooperate in accord with embodiments of the present disclosure. Thoseskilled in the art are familiar with instructions, processor(s), andstorage medium.

Smart PV inverters may incorporate similar shunt-VAR control technologyas discussed above with reference to FIGS. 1-15. Specifically, theshunt-VAR control technology may drive the VAR injection (lead and lag)in PV inverters. The voltage drop across lines and service transformersin the distribution circuit with high PV penetration may be approximatedwith the relationship shown below in Equation 1, and a representativedistribution circuit with high PV is shown in FIG. 19. In this equation,and with respect to FIG. 19, ΔV_(T) represents the voltage drop acrosslines and transformers, I_(L) represents the load current, PF is thepower factor of the load, I_(G) is the current generated by PV solargenerator, PF_(G) is the power factor at which power is produced by thePV generator, X and r are the reactance and resistance of lines andservice transformers respectively. σ_(Q) is a parameter which takesvalues +1 or −1 depending on whether the PV inverter generates laggingVARs (i.e., absorbs VARs) or generates leading VARs (i.e., injectsVARs), respectively.ΔV _(T) ≈rI _(L) PF+XI _(L)√{square root over (1−PF ²)}+σ_(Q) XI_(G)√{square root over (1−PF _(G) ²)}−rI _(G) PF _(G)  (1)

The trailing term in Equation 1, rI_(G)PF_(G), is negative and iscontributed by the PV generator. If I_(L) (load current) is much smallerthan I_(G) (PV generator current) then the total drop may becomenegative, meaning voltage on the secondary side can be larger thanvoltage on the primary. As solar energy is intermittent, I_(G) maychange very frequently, which may cause large variations and volatilityin ΔV_(T) (voltage drop across the service transformers and lines). Ifthe PF_(G) is not equal to unity (e.g., 0.95), a fixed positive dropdependent on solar generation (I_(G)) may be introduced. This term helpsmanage the rise in voltage at the secondary by increasing the positivedrop on the lines and service transformers.

Still referring to Equation 1, ΔV_(T) may be controlled by adjusting thesecond to the last term in the relations, σ_(Q)XI_(G)√{square root over(1−PF_(G) ²)}. For example, reactive power may be varied dynamically(i.e., indirectly) by varying σ_(Q) and PF_(G) to control ΔV_(T) (e.g.,to maintain a near zero voltage or control the voltage at the point ofconnection of the solar PV inverter based on a commanded set point). Theset point may be pre-programmed in the smart inverter, set duringmaintenance activities, or controlled from a central location.

Depending on the information available at the PV inverter, differentrelationships, or variations of the relationship illustrated in Equation1, may be used to regulate voltage. For example, if the PV inverter iscommanded to regulate voltage at a fixed set point and only has localvoltage information, the Zero Droop Voltage (ZDV) control relationshipmay be leveraged as illustrated, for example, in FIG. 20. A person ofskill in the art would appreciate that variations of the processillustrated in FIG. 20 for controlling local voltage information using aZDV control relationship and other similar methods may be used tocontrol voltage information using a ZDV control relationship.

FIG. 18A is a chart showing measured voltage volatility over multipledistribution transformers when now edge of network voltage control isused. As illustrated, without implementing an edge of network voltagecontrol mechanism, voltage volatility can be very high. In contrast,when shunt-VAR voltage control is employed at the edge of the network,including using ZDV relationships to fix set-points for smart inverterVAR insertion or absorption at the edge of the grid, voltage volatilitycan be dramatically reduced as illustrated by the chart of measuredvoltages over multiple distribution transformers shown in FIG. 18B.

FIG. 20 is an example method of generating a Q_(ref) value for a smartinverter. Referring now to FIG. 20, a method for generating a Q_(ref)value in a smart inverter may include initializing an inverter rating S,voltage set-point V_(sp), and voltage band B at step 2702. Theinitialization of these values may be controlled through pre-programmingin inverter logic (e.g., the Q_(ref) calculator logic depicted in FIGS.21A and 21B), set during intermittent, scheduled, or ad hoc calibrationperiods, or controlled via signaling from a central location. The methodmay also include receiving V(t) at step 2704. V(t) for example may bethe measured voltage (e.g., at the edge of the network or othermeasurement points). In some embodiments, the method may also includedetecting whether there is voltage oscillation (e.g., based on voltageor current measurements) at step 2706, and if oscillation is detected,maintaining the VAR value for a random period of time before determiningwhether to inject or absorb a VAR (i.e., setting a delay timer to arandom value) at step 2710. In some examples, the delay is not random,but instead, may be predetermined or set via an algorithm. If no voltageoscillation is detected at step 2706, then the random delay at step 2710need not be implemented.

The method may also include getting V(t), Q_(inj), Q_(max), V_(sp), andDB values at step 2712. Q_(max) may be calculated using the relationshipQ_(max)=√{square root over (S²−P_(ref) ²)}. These values may beestablished through pre-programming in inverter logic (e.g., the Q_(ref)calculator logic depicted in FIGS. 21A and 21B), set duringintermittent, scheduled, or ad hoc calibration periods, or controlledvia signaling from a central location. These values may also becalculated as described herein.

Still referring to FIG. 20, a method of generating a Q_(ref) value for asmart inverter may also include randomizing a gain value, K_(T) at step2714 and generating control error e_(v) and delay time Td values (e.g.,a timer value) at step 2716. For example, e_(v) may be the differencebetween V(t) and Vsp as V(t)−Vsp, and Td may be calculated asK_(T)/(abs(e_(v))).

The method may further include comparing the absolute value of e_(v)with the band B at step 2718. If abs(e_(v)) is not greater than B, thenthe method may include getting a new set of values V(t), Q_(inj),Q_(max), V_(sp), and DB at step 2712, and reimplementing steps 2714 and2716. Alternatively, if abs(e_(v)) is not greater than B, then themethod may include setting and waiting for a delay, T_(d), getting a newV(t) value, and generating e_(v)=V(t)−V_(sp) at step 2722.

The method may further include comparing the absolute value of the e_(v)calculated at step 2722 with the band B and determining whether e_(v) isgreater or less than 0 at steps 2724 and 2726. At step 2724, ifabs(e_(v)) is greater than B and e_(v) is greater than 0, then the PVinverter can be set to absorb VARs (i.e., lagging VARs) at step 2730 bycalculating a change in Q_(ref) as Q_(ref)=K_(q)*e_(v) ². In someexamples, K_(q) may be set to a random value. If abs(e_(v)) is greaterthan B and e_(v) is less than 0, the PV inverter can be set to injectVARs (i.e., leading VARs) at step 2732 by calculating a change inQ_(ref) as Q_(ref)=−K_(q)*e_(v) ². Or, as another option, if abs(ev) isequal to or less than B, Q_(ref) may remain unchanged at step 2738 andno change will be made to Q_(ref) at step 2734.

The method may also include determining whether the absolute value ofQ_(ref) exceeds Q_(max) at step 2736, and if Q_(ref) does exceedQ_(max), adjusting Q_(ref) by multiplying Q_(max) by the sign of Q_(ref)at step 2732. Other methods of reducing Q_(ref) may be used to ensurethat Q_(ref) is less than Q_(max). The method may also include updatedthe current reference Q value (i.e., the smart inverter referencevoltage set-point) with the generated Q_(ref) value at step 2740.

FIG. 21A is a block diagram of a smart inverter incorporating a Q_(ref)calculator 2110. The Q_(ref) calculator 2110 may include a processor andnon-transitory computer readable memory with software embedded thereon,the software configured to perform the Q_(ref) generation methoddescribed above with reference to FIG. 20. As illustrated in FIG. 21A, aPV inverter 2150 may electrically couple to the utility grid edge. PVinverter 2150 may include or communicate with sensors to measure valuesfor V and I, and calculate P and Q in measurement component 2102. PVinverter 2150 may also include PV inverter power hardware 2104 PVinverter switching logic 2106, and a reference P calculator 2108.Q_(ref) calculator 2110 may communicate with the other components of PVinverter 2100 to initialize and or receive values for S, V_(sp), B,V(t), Q_(inj), and DB, and then return update Q_(ref) values in realtime or intermittently. In this regard, PV inverter 2110 may calculateits own Q_(ref) values without communicating with other smart invertersor with the network, other than measuring voltage levels at the gridedge. Infighting is minimized using the same principles as discussedabove with respect to shunt-VARs referenced in FIGS. 1-15.

In an alternate embodiment, FIG. 21B is a block diagram of a smartinverter in communication with an external Q_(ref) calculator 2160. TheQ_(ref) calculator 2160 may include a processor and non-transitorycomputer readable memory with software embedded thereon, the softwareconfigured to perform the Q_(ref) generation method described above withreference to FIG. 20. The other components and functionality of PVinverter 2150 may be similar to the components and functionality of PVinverter 2110 discussed above in reference to FIG. 21B. Qref calculator2160 may communicate with the other components of PV inverter 2150 toinitialize and or receive values for S, Vsp, B, V(t), Qinj, and DB, andthen return update Qref values in real time or intermittently.

FIG. 22 depicts an example power distribution system with smartinverters. For example, one or more of the smart inverters illustratedin FIG. 22 may incorporate Q_(ref) calculators or communicate withexternal Q_(ref) calculators as discussed above with reference to FIGS.21A and 21B.

As used herein, the term module might describe a given unit offunctionality that can be performed in accordance with one or moreembodiments of the present application. As used herein, a module mightbe implemented utilizing any form of hardware, software, or acombination thereof. For example, one or more processors, controllers,ASICs, PLAs, PALs, CPLDs, FPGAs, logical components, software routinesor other mechanisms might be implemented to make up a module. Inimplementation, the various modules described herein might beimplemented as discrete modules or the functions and features describedcan be shared in part or in total among one or more modules. In otherwords, as would be apparent to one of ordinary skill in the art afterreading this description, the various features and functionalitydescribed herein may be implemented in any given application and can beimplemented in one or more separate or shared modules in variouscombinations and permutations. Even though various features or elementsof functionality may be individually described or claimed as separatemodules, one of ordinary skill in the art will understand that thesefeatures and functionality can be shared among one or more commonsoftware and hardware elements, and such description shall not requireor imply that separate hardware or software components are used toimplement such features or functionality.

Where components or modules of the application are implemented in wholeor in part using software, in one embodiment, these software elementscan be implemented to operate with a computing or processing modulecapable of carrying out the functionality described with respectthereto. One such example computing module is shown in FIG. 23 which maybe used to implement various features of the system and methodsdisclosed herein. Various embodiments are described in terms of thisexample-computing module 2300. After reading this description, it willbecome apparent to a person skilled in the relevant art how to implementthe application using other computing modules or architectures.

Referring now to FIG. 23, computing module 2300 may represent, forexample, computing or processing capabilities found within aself-adjusting display, desktop, laptop, notebook, and tablet computers;hand-held computing devices (tablets, PDA's, smart phones, cell phones,palmtops, etc.); workstations or other devices with displays; servers;or any other type of special-purpose or general-purpose computingdevices as may be desirable or appropriate for a given application orenvironment. For example, computing module 2300 may be one embodiment ofthe data acquisition and control module of FIG. 23, a distributed VARsource device, and/or one or more functional elements thereof. Computingmodule 2300 might also represent computing capabilities embedded withinor otherwise available to a given device. For example, a computingmodule might be found in other electronic devices such as, for examplenavigation systems, portable computing devices, and other electronicdevices that might include some form of processing capability.

Computing module 2300 might include, for example, one or moreprocessors, controllers, control modules, or other processing devices,such as a processor 2304. Processor 2304 might be implemented using ageneral-purpose or special-purpose processing engine such as, forexample, a microprocessor, controller, or other control logic. In theillustrated example, processor 2304 is connected to a bus 2302, althoughany communication medium can be used to facilitate interaction withother components of computing module 2300 or to communicate externally.

Computing module 2300 might also include one or more memory modules,simply referred to herein as main memory 2308. For example, preferablyrandom access memory (RAM) or other dynamic memory might be used forstoring information and instructions to be executed by processor 2304.Main memory 2308 might also be used for storing temporary variables orother intermediate information during execution of instructions to beexecuted by processor 2304. Computing module 2300 might likewise includea read only memory (“ROM”) or other static storage device coupled to bus2302 for storing static information and instructions for processor 2304.

The computing module 2300 might also include one or more various formsof information storage mechanism 2310, which might include, for example,a media drive 2312 and a storage unit interface 2320. The media drive2312 might include a drive or other mechanism to support fixed orremovable storage media 2314. For example, a hard disk drive, a solidstate drive, a magnetic tape drive, an optical disk drive, a compactdisc (CD) or digital video disc (DVD) drive (R or RW), or otherremovable or fixed media drive might be provided. Accordingly, storagemedia 2314 might include, for example, a hard disk, an integratedcircuit assembly, magnetic tape, cartridge, optical disk, a CD or DVD,or other fixed or removable medium that is read by, written to oraccessed by media drive 2312. As these examples illustrate, the storagemedia 2314 can include a computer usable storage medium having storedtherein computer software or data.

In alternative embodiments, information storage mechanism 2310 mightinclude other similar instrumentalities for allowing computer programsor other instructions or data to be loaded into computing module 2300.Such instrumentalities might include, for example, a fixed or removablestorage unit 2322 and an interface 2320. Examples of such storage units2322 and interfaces 2320 can include a program cartridge and cartridgeinterface, a removable memory (for example, a flash memory or otherremovable memory module) and memory slot, a PCMCIA slot and card, andother fixed or removable storage units 2322 and interfaces 2320 thatallow software and data to be transferred from the storage unit 2322 tocomputing module 2300.

Computing module 2300 might also include a communications interface2324. Communications interface 2324 might be used to allow software anddata to be transferred between computing module 2300 and externaldevices. Examples of communications interface 2324 might include a modemor softmodem, a network interface (such as an Ethernet, networkinterface card, WiMedia, IEEE 802.XX or other interface), acommunications port (such as for example, a USB port, IR port, RS232port Bluetooth® interface, or other port), or other communicationsinterface. Software and data transferred via communications interface2324 might typically be carried on signals, which can be electronic,electromagnetic (which includes optical) or other signals capable ofbeing exchanged by a given communications interface 2324. These signalsmight be provided to communications interface 2324 via a channel 2328.This channel 2328 might carry signals and might be implemented using awired or wireless communication medium. Some examples of a channel mightinclude a phone line, a cellular link, an RF link, an optical link, anetwork interface, a local or wide area network, and other wired orwireless communications channels.

In this document, the terms “computer program medium” and “computerusable medium” are used to generally refer to transitory ornon-transitory media such as, for example, memory 2308, storage unit2320, media 2314, and channel 2328. These and other various forms ofcomputer program media or computer usable media may be involved incarrying one or more sequences of one or more instructions to aprocessing device for execution. Such instructions embodied on themedium, are generally referred to as “computer program code” or a“computer program product” (which may be grouped in the form of computerprograms or other groupings). When executed, such instructions mightenable the computing module 2300 to perform features or functions of thepresent application as discussed herein.

Although described above in terms of various exemplary embodiments andimplementations, it should be understood that the various features,aspects and functionality described in one or more of the individualembodiments are not limited in their applicability to the particularembodiment with which they are described, but instead can be applied,alone or in various combinations, to one or more of the otherembodiments of the application, whether or not such embodiments aredescribed and whether or not such features are presented as being a partof a described embodiment. Thus, the breadth and scope of the presentapplication should not be limited by any of the above-describedexemplary embodiments.

Terms and phrases used in this document, and variations thereof, unlessotherwise expressly stated, should be construed as open ended as opposedto limiting. As examples of the foregoing: the term “including” shouldbe read as meaning “including, without limitation” or the like; the term“example” is used to provide exemplary instances of the item indiscussion, not an exhaustive or limiting list thereof; the terms “a” or“an” should be read as meaning “at least one,” “one or more” or thelike; and adjectives such as “conventional,” “traditional,” “normal,”“standard,” “known” and terms of similar meaning should not be construedas limiting the item described to a given time period or to an itemavailable as of a given time, but instead should be read to encompassconventional, traditional, normal, or standard technologies that may beavailable or known now or at any time in the future. Likewise, wherethis document refers to technologies that would be apparent or known toone of ordinary skill in the art, such technologies encompass thoseapparent or known to the skilled artisan now or at any time in thefuture.

The presence of broadening words and phrases such as “one or more,” “atleast,” “but not limited to” or other like phrases in some instancesshall not be read to mean that the narrower case is intended or requiredin instances where such broadening phrases may be absent. The use of theterm “module” does not imply that the components or functionalitydescribed or claimed as part of the module are all configured in acommon package. Indeed, any or all of the various components of amodule, whether control logic or other components, can be combined in asingle package or separately maintained and can further be distributedin multiple groupings or packages or across multiple locations.

What is claimed is:
 1. A system for controlling grid voltage, the systemcomprising: a power distribution network; an inverter electricallycoupled to an edge of the power distribution network, the inverterconfigured to, based on a reference Q value, insert volt-ampere reactive(VARs) or absorb VARs at the edge of the power distribution network; anda reference Q calculator communicatively coupled to or embedded on acontroller disposed within the inverter, the reference Q calculatorcomprising a processor and a non-transitory computer readable memorywith software embedded thereon, the software configured to cause theprocessor to: receive a voltage measurement taken at the edge of thepower distribution network, a voltage band value, and a voltage setpoint value; determine a difference, e_(v), between the voltagemeasurement and the voltage set point value; and generate a newreference Q value if an absolute value of e_(v) is greater than thevoltage band value.
 2. The system of claim 1, wherein the new referenceQ value is set to trigger the inverter to absorb VARs if e_(v) isnegative in value.
 3. The system of claim 1, wherein the new reference Qvalue is set to cause the inverter to inject VARs if e_(v) is positivein value.
 4. The system of claim 1, wherein the software is furtherconfigured to cause the processor to generate the new reference Q valueas a function of e_(v) ².
 5. The system of claim 4, wherein the softwareis further configured to cause the processor to generate the newreference Q value as a function of a randomized gain value, K_(q). 6.The system of claim 1, wherein the reference Q calculator is disposedwithin the inverter.
 7. The system of claim 1, wherein the reference Qcalculator is external to the inverter.
 8. The system of claim 7,wherein the software is further configured to cause the processor toreceive a maximum Q reference value and to limit the new reference Qvalue to the maximum Q reference value.
 9. The system of claim 8,wherein the software is further configured to cause the processor to seta delay timer if the voltage measurement is oscillating and to maintaina current reference Q value until the delay timer expires.
 10. Thesystem of claim 9, wherein the software is further configured to causethe processor to receive a rating S, and the maximum Q reference valueis set as function of S.
 11. The system of claim 1, wherein the voltageband value is set by a user.
 12. A method of controlling voltage at anedge of a power distribution network, the method comprising: receiving avoltage measurement from the edge of the power distribution network, avoltage band value, and a voltage set point value; determining adifference, e_(v), between the voltage measurement and the voltage setpoint; generating a new reference Q value of an inverter if an absolutevalue of e_(v) is greater than the voltage band value, wherein theinverter is electrically coupled to the edge of the power distributionnetwork; and based on the new reference Q value, the inverter insertingVARs or absorbing VARs at the edge of the power distribution network.13. The method of claim 12, further comprising: causing the inverter toabsorb VARs at the edge of the power distribution network, based on thenew reference Q value, if e_(v) is negative in value.
 14. The method ofclaim 12, further comprising: causing the inverter to inject VARs at theedge of the power distribution network, based on the new reference Qvalue, if e_(v) is positive in value.
 15. The method of claim 12,wherein the new reference Q value is generated as a function of e_(v)^(e).
 16. The method of claim 15, further comprising generating arandomized gain value, K_(q), wherein the new reference Q value isgenerated as a function of K_(q).
 17. The method of claim 16, furthercomprising generating a maximum Q reference value and to limiting thenew reference Q value to the maximum Q reference value.
 18. The methodof claim 17, further comprising receiving a rating S and generating themaximum Q reference value as a function of S.
 19. The method of claim12, further comprising setting a delay if the voltage measurement isoscillating and maintaining a current reference Q value until the delayexpires.
 20. The method of claim 19, further comprising generating arandomized value, K_(T), wherein the delay is set as a function of K_(T)and e_(v) is generated as a function of K_(q).